Chemical compositions and treatment systems and treatment methods using same for remediating  h2s and other contaminants in fluids, including liquids,gasses and mixtures thereof

ABSTRACT

A treatment composition for remediating for remediating H2S and other contaminant(s) in contaminated gasses comprising: an aqueous hydroxide solution containing at least one hydroxide compound at a collective concentration of 35-55 weight percent of the aqueous hydroxide solution; at least one organic acid selected from the group consisting of fulvic acid and humic acid; and a chelating agent, wherein the aqueous hydroxide solution constitutes at least 80 wt % of the treatment composition, the at least one organic acid constitutes 0.1-3 wt % of the treatment composition, the chelating agent constitutes 0.1-6 wt % of the treatment composition, and a pH of the treatment composition is at least 12.0.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation-in-part (CIP) of U.S.Non-provisional application Ser. No. 16/857,884, which claims thebenefit of priority to U.S. Provisional Patent Application No.62/903,425, filed Sep. 20, 2019. The present CIP application also claimspriority from U.S. Provisional Patent Application No. 63/064,643, filedAug. 12, 2020 and U.S. Provisional Patent Application No. 63/111,400,filed Nov. 9, 2020, The entire subject matter of each of these priorityapplications, including specification claims and drawings thereof, isincorporated by reference herein.

BACKGROUND OF THE INVENTION 1. Field of the Invention

The present disclosure relates to novel treatment compositions andtreatment methods for remediating sulfur-containing compounds, includingH₂S, and other contaminants in various fluids, including hydrocarbonbased liquids such as crude oil and contaminated water extracted withcrude oil from the earth, hydrocarbon based gasses such as natural gasand mixtures of such liquids and gasses. More particularly, the presentdisclosure relates to such treatment systems, methods and compositionsin which the contaminated fluids are chemically reacted with thetreatment compositions in the treatment systems and treatment methodswhereby the contaminants in the fluids are remediated to varyingdegrees, including down to very low levels that have been deemed safe ina practical, efficient and economical manner.

2. Background

Sulfur-containing compounds including hydrogen sulfide (H₂S) have longbeen recognized as undesirable contaminants in hydrocarbon liquids suchas crude oil and liquified petroleum gas (LPG), as well as inhydrocarbon gasses such as natural gas, and aqueous solutions such assolutions extracted from the earth along with crude oil and in naturalgas. H₂S is a particularly undesirable contaminant because it is highlytoxic, corrosive, etc. and generally hydrocarbon liquids and gassesshould contain less than four ppm H₂S. Remediation of H₂S in hydrocarbonliquids and gasses has long been and remains a very important focus ofpetroleum industries around the world.

Further, many of the hydrocarbon liquids and gasses which are extractedfrom the ground may contain significant amounts of many othercontaminants, including carbon dioxide, sodium chloride, nitrogen, etc.,which should also be remediated down to low, acceptable levels toimprove the quality and value of the hydrocarbon liquids and gasses.

However, the presence of these other contaminants will typicallycomplicate the treatment required for remediating H₂S, and hasconventionally required additional, special treatment compositions andmethods beyond those used for remediating H₂S in the contaminatedliquids and gasses. A particular complicating factor in treatingnaturally occurring hydrocarbon based liquids and gasses such as crudeoil and natural gas, is the fact that such liquids and gasses typicallyhave widely varying characteristics that must be considered. Forexample, even in relation to one given oil well or natural gas well, thecrude oil and aqueous solutions extracted therefrom have characteristicswhich can vary greatly, e.g., crude oil or natural gas extracted from agiven well at a given time on a given day, can contain amounts of H₂S,as well as various types and amounts of other contaminants, which aresignificantly different from those contained in crude oil or natural gasextracted from the same well on the same day, but at a different time.

There are many known methods for remediating sulfur-containingcompounds, including H₂S, from crude oil and other liquids. For example,M. N. Sharak et al., Removal of Hydrogen Sulfide from HydrocarbonLiquids Using a Caustic Solution, Energy Sources, Part A: Recovery,Utilization, and Environmental Effects, 37:791-798, 2015, discuss that:the known methods include amine processes involving monoethanolamine(MEA), triazine, etc., treatment involving use of caustic material, ironoxide process, zinc oxide, molecular sieve, potassium hydroxide, and ahydrodesulphurization process; the amine treatment is usually the mostcost effective choice for gas sweetening when significant amounts ofacid gases exist; scrubbing of hydrogen sulfide using sodium hydroxidesolution is a well established technology in refinery applications;caustic wash process is commonly used as a preliminary step insweetening liquid hydrocarbons; and since the used solvent in thisprocess cannot be easily regenerated, caustic scrubbers are most oftenapplied where low acid gas (H₂S) volumes must be treated.

H₂S remediation achieved by a conventional amine treatment process usesan amine such as monoethanolamine (MEA) or triazine for treating H₂S incrude oil. However, with the conventional amine treatment process, whilethe H₂S may be initially remediated or abated down to acceptable levels,the sulfur contained in the treated oil may undesirably revert back toH₂S over time, especially if the treated oil is heated. Somewhatsimilarly, it is also known that there are bacteria which ingest sulfurcompounds, and hence may reduce the amounts of sulfur contaminants inhydrocarbon based liquids or contaminated aqueous solutions. However,when the bacteria die and decompose this undesirably releases the sulfurback into the hydrocarbon based liquids or contaminated aqueoussolutions.

A conventional caustic treatment used to remediate H₂S in crude oilinvolves use of a caustic aqueous solution consisting of up to 20% NaOHby weight. The water and caustic material are used to extract H₂S fromthe crude oil into solution, dissociating H₂S to HS— ion at higher pH,which shifts the equilibrium of H₂S gas from oil to water. Then, the HS—can react with sodium to form NaHS (sodium bisulfide), or with S₂— toform Na₂S (sodium sulfide), for example, plus water as a byproductaccording to the following equations.

H₂S+NaOH→NaHS+H₂O  (1)

NaHS+NaOH→Na₂S+H₂O  (2)

Generally, the conventional caustic treatment methods are limited tousing caustic solutions of only up to 20 weight percent NaOH because theconventional methods are designed and intended to be partly aliquid-liquid extraction, and partly a chemical reaction to convert theH₂S gas to a solid sulfurous species. It is conventionally understoodthat a certain amount of water is needed to permit the chemicalreactants to contact with the crude oil or other petroleum based liquid.The larger amounts of water contained in the conventional caustictreatment solutions permit a greater amount of liquid-liquid extraction.Also, it is known that use of excessive amounts of NaOH may damage thecrude oil, as well as metal components used handling the crude oil suchas pipes and tanks.

Additionally, some of the H₂S may be converted into sulfur dioxide (SO₂)gas, e.g., upon stirring which allows air containing oxygen to get intothe oil, which may be released from the treated petroleum based liquid,depending on the pressure under which the treated liquid is kept.Generally, hydroxides including NaOH are reducing agents and would notproduce sulfur dioxide or elemental sulfur if the treated hydrocarbonbased liquid is not exposed to air. However, if the oil is exposed toair, the sulfide/bisulfide can be oxidized to SO₂ or to elementalsulfur. All sulfide species are the same oxidation state (−2) and NaOHis not changing the oxidation state. Similar reactions would occur forother hydroxides included in the treatment solution. Relative to anysuch sulfur dioxide (SO₂) gas, as well as any other gases that may bereleased from the treated crude oil, it would be necessary as a safetymeasure to provide some head space in a closed tank or other closedvessel transporting the treated liquid to assure that the pressure doesnot get excessively high.

Recently, some of the present inventors have proposed other treatmentcompositions and processes for remediating H₂S and other contaminants,as set forth in International Application Nos. PCT/US2018/050913 andPCT/US2018/064015, the contents of these International Applications areincorporated herein by reference. The previously proposed treatmentcompositions have proven to be very efficient for remediatingsulfur-containing compounds, including H₂S, from hydrocarbon basedliquids including crude oil, and from contaminated aqueous solutions,much more so than other conventionally known treatment compositions, andwith no undesirable effects.

One of the proposed processes involves an aqueous treatment solutioncontaining primarily a high concentration of one or more hydroxides suchas sodium hydroxide (NaOH) and potassium hydroxide (KOH), e.g.,collectively the hydroxides account for 35-55 weight percent, andpreferably at least 45 weight percent of the treatment solution, whichefficiently react with H₂S to convert it to non-toxic substances. Suchtreatment solution according to the recent proposal is highly alkalinewith a pH of 13-14. In such treatment process the treatment solution isadded to the hydrocarbon based liquids or aqueous solutions beingtreated at appropriate dosage rates depending on multiple factors, andthe hydroxide(s) in the solution efficiently remediate the H₂S and othersulfur-containing compounds down to acceptable levels within relativelyshort time periods, and without otherwise detrimentally affecting thehydrocarbon-petroleum based liquids or contaminated aqueous solutions inany significant manner. The recently proposed treatment solution mayfurther include one or more other components depending on the specificcharacteristics of the liquids being treated and other factors relatingto the remediation treatment process. For example, the treatmentsolution may include a silicate such as potassium silicate (K₂SiO₃) orbarium (Ba) as an antibacterial agent, but the high concentration ofhydroxide(s) in the treatment solution is a primary characteristic ofthe solution because this is important for efficient remediation of H₂Sby the hydroxide(s) in the liquids being treated.

Such recently proposed treatment process is based on the inventors'discovery that the conventional treatment methods using an aqueoussolution consisting of up to 20% NaOH by weight is inefficient forremediating H₂S, and that the H₂S in contaminated liquids can be muchmore efficiently remediated using their proposed treatment solutioncontaining a much higher collective concentration of one or morehydroxides. The inventors' recently proposed treatment process is not awash type process, but involves rapid chemical reactions that greatlyreduce the mass transfer of the gas to aqueous phase. What the treatmentprocess does differently in comparison to the conventional treatmentprocesses for remediating H₂S in hydrocarbon based liquids, is toessentially reduce the initial amount of water being added via thetreatment solution to the minimum effective amount.

While it is known that H₂S gas is more soluble in oil than in water andthat a rate-limiting step in the remediation of H₂S from crude oil istypically the mass transfer of H₂S from the oil phase into the aqueousphase, the inventors have discovered that: the liquid-liquid extractionaspect of the conventional methods is actually not that important incomparison to the chemical reaction aspect, e.g., because the initialsolubility of H₂S into water, as given by Henry's Law, is low; thelarger amounts of water used in aqueous treatment solutions according tothe conventional methods also function to dilute the NaOH and transferthe H₂S from the hydrocarbon liquid into the water without abating theH₂S, which is undesirable because this slows the process needed toproduce ionized HS— and S₂— ions that allow more of the H₂S contained inthe petroleum liquids into solution, and it is much more efficient andeffective to remove the H₂S primarily though a chemical reaction processand to a much lesser degree a liquid-liquid extraction. The presentinventors have also discovered that since the chemical reactionsinvolved between hydroxides and H₂S, e.g., equations (1), (2) above,produce water, the produced water can readily diffuse through thehydrocarbon based liquid being treated as it is produced because thecaustic solution has good migration tendencies in many hydrocarbon basedliquids and the diffusion may also be enhanced by agitation and/orheating of the treated liquids. Correspondingly, they determined that itis unnecessary to add any significant amount of water in the treatmentprocess apart from the water in the treatment solution in order for thehydrocarbon based liquid to be effectively treated for remediation ofsulfur-containing contaminants, including H₂S, and other contaminantstherein. Relative to the inventors' discovery 1), it should be notedthat equation (2) above is reversible, so large amounts of waterhydrolyze the sodium sulfide (Na₂S) back to NaOH and NaHS. In otherwords, equation (2) in the reverse direction is a hydrolysis reaction.

Such recently proposed treatment process may involve use of only onehydroxide such as sodium hydroxide (NaOH) or potassium hydroxide (KOH),but may also involve use of a combination of hydroxides for morecompletely reacting with most or all of the sulfides in the petroleumbased liquids, noting that there are more than 300 species of sulfurcompounds, although hydrogen sulfide H₂S is by far the main contaminantthat must be remediated. For example, some other species of undesirablesulfur compounds include ethyl mercaptan (CH₃CH₂SH), dimethyl sulfide(C₂H₆S), isobutyl mercatan (C₄H₁₀S) and methyl thiophene (C₅H₆S). Sodiumhydroxide is very effective for use in the treatment solution because itdoes not harm the petroleum based liquids when used in appropriateamounts, and is relatively inexpensive. Potassium hydroxide is moreeffective than sodium hydroxide for reacting with some species ofsulfides. Hence, the treatment process involving potassium hydroxide(KOH) together with the sodium hydroxide achieves a more completereaction with all of the sulfides contained in the hydrocarbon basedliquids in comparison to just using a concentrated solution of sodiumhydroxide.

In such proposed treatment process for remediating contaminated liquids,the treatment solution may be added at a standard dosage rate of0.25-6.0 ml of the treatment solution/liter of the liquid being treated,preferably 1.0-5.0 ml of the treatment solution/liter of the liquidbeing treated, which corresponds to approximately 250-6000 ppm of thetreatment solution in the liquid being treated based on the discussedconcentration of hydroxide(s) in the solution. The discussed standarddosage rate is generally effective for remediating H₂S concentrations upto down to safe, acceptable levels. 40,000 ppm H₂S may be experienced insome hydrocarbon based liquids such as crude oil, although contaminatedaqueous solutions typically have a much lower H₂S concentration such as2000 ppm or less. If the amount of the treatment solution added is below0.25 ml/liter of liquid being treated, sufficient remediation of H₂S maynot be archived, and the reactions between the treatment solution andthe sulfide compounds in the hydrocarbon based liquid may not proceedquickly and/or efficiently. If the concentration of H₂S is higher than40,000 ppm it may be necessary to increase standard dosage amount of therecently proposed treatment solution appropriately, which may generallyinvolve linear scalability. Dosage levels above 6.0 ml of the treatmentsolution/liter of the liquid being treated generally do not furtherreduce H₂S levels in the treated liquids where reaction times are not aconsideration, but can advantageously reduce required reaction times ifso desired.

Within the discussed standard dosage rate range, a most appropriatedosage amount of the treatment solution to be added to a contaminatedliquid during the treatment process may be determined based on a fewconsiderations, e.g., the amounts of H₂S and other contaminants in theliquid that need to be remediated, other characteristics of the liquidincluding its viscosity or API density (the term API as used herein, isan abbreviation for American Petroleum Institute), desired reactionrate/time, specific result desired including whether precipitate(s) areto be formed and released from the liquid, and whether the treatedliquid is being mixed and/or heated during the treatment process. Forexample, mixing at moderate to high speeds to rapidly disperse thetreatment solution throughout the treated liquid may reduce requiredreaction time by 50%, whereas some highly viscous liquids such as bunkerfuel may require heating to permit proper dispersion of the treatmentsolution therein. The appropriate dosage rate is substantially, linearlyscalable in relation to most or all of the various characteristicswithin the standard dosage rate range.

Advantageously, the recently proposed treatment process is generallyefficient and effective as long as the amount of the treatment solutionadded is within the discussed standard dosage rate range, whether or notthe amount of treatment solution added is the most appropriate dosageamount for the given liquid being treated. Further, use of higheramounts of the treatment solution may be desirable in some situations,and generally will not cause any significant problems or complications,although higher dosage amounts generally tend to cause precipitate(s) tobe generated and released from the treated liquids. For example, theinventors have further determined that if an intentionally excessivedosage of the first recently proposed treatment solution is added to aliquid being treated such as 2-5 times the standard dosage ratesdiscussed above, this will likely cause remediated contaminants andother contaminants in the treated liquid to precipitate out of thetreated liquid, which may be desirable in some situations. Also,depending on how much of the treatment solution is used in excess of thestandard dosing rate, this may generate different precipitates whichseparate out of the treated liquid so that the outcome may be controlledin desired manners, e.g., at 2 times the standard dosing rate a hydrateof sodium sulfide such as Na₂S.9H₂O may precipitate out of the treatedliquid according to the reaction (2) above, while at a higher dosagerate of 3 to 5 times the standard dosage rate, this may cause elementalsulfur to precipitate out of the treated liquid. Otherwise, the excessdosages of hydroxides in the treatment process will increase the cost ofthe treatment, but generally do not have any significantly adverseeffects on the treated hydrocarbon based liquids and aqueous solutions.However, application of a very excessive amount of the solution, e.g.,ten times the normal amount, may render the treated petroleum basedliquid caustic which could be damaging to metals such as steel andaluminum used for containing and transporting the treated liquids.

Reaction times for the inventors' recently proposed treatment processare typically within a relatively short time period such as 15minutes-24 hours after such treatment solution is added to the liquid atthe discussed dosage rate, whether the liquid being treated is ahydrocarbon based liquid such as crude oil or a contaminated aqueoussolution. Within such time period, the hydroxide(s) in the solutionremediate the H₂S and other sulfur based contaminants down to safe,acceptable levels such as 5 ppm or less, and without generating orreleasing any particularly harmful substances. For example, when thetreatment solution includes sodium hydroxide (NaOH) as the primaryhydroxide therein, e.g., at least 90% of all hydroxides in the solution,much of the H₂S, e.g., at least 60% is converted into sodium bisulfide(NaHS) according to the reaction (1) above, which remains dissolved inthe treated petroleum liquid, and does not create any significantproblems that would need to be addressed. Additionally, some of the H₂Smay be converted into sulfur dioxide (SO₂) gas which may be releasedfrom the treated petroleum based liquid, depending on the pressure atwhich the treated liquid is kept.

Very desirably, the proposed treatment process is generally notreversible in relation to the H₂S and other sulfur contaminants whichhave been remediated, e.g., even if the treated liquid is heated up to180° F. for a period of days or weeks, any remediated sulfur compoundsremaining in the treated liquids do not revert back to H₂S. Someconventional treatment processes for remediating H₂S are undesirablyreversible, including the conventional amine treatment process whichuses an amine such as MEA or triazine for treating H₂S in crude oil. Forexample, with the conventional amine treatment process, while the H₂Smay be initially remediated or abated down to acceptable levels, thesulfur contained in the treated oil may undesirably revert back to H₂Sover time, especially if the treated oil is heated. Conversely, whencrude oil which initially contained about 1000 ppm H₂S was treatedaccording to a treatment process using the treatment solution accordingto the inventor's recent proposal at a dosing rate of 3 ml/liter of oiland the H₂S was abated down to about 0 ppm and essentially none of thesulfur precipitated out of the oil, the treated crude oil was heated upto 180-300° F. or 82.2-148.9° C. for periods of hours, days and weeks,the resulting oil still contained about 0 ppm H₂S. Essentially none ofthe sulfur compounds(s) in the treated liquid reverted back to H₂S.

According to a second proposal by some of the present inventors, thefirst proposed treatment composition and process are modified orsupplemented such that the contaminants in the treated liquids are notonly remediated, but remediated in such a manner that essentially noprecipitates or scale are generated in the treated liquids. In the firstproposed treatment process if only a standard dosing rate of thetreatment solution is added to a liquid being treated, there may belittle or no precipitate(s), scaling or the like formed from the treatedliquids, but even small amounts of precipitate(s), scaling or the likemay be undesired or unacceptable in some situations. One particularapplication in which it is very important to assure that noprecipitates, scale and the like will be generated from the treatedhydrocarbon based liquids is when crude oil directly from the ground isbeing transported via pipeline, tanker truck or other vessel to a majorpipeline, which then transports the crude oil to a refinery. Some of themajor pipelines generally will not accept crude oil containing more than5 ppm H₂S, although some of the major pipelines are structured to handleand will accept a higher H₂S content particularly where the pipelinesare intended to receive a mixture of contaminated crude oil andcontaminated natural gas. By treating the crude oil with a standarddosage of the treatment solution according to the inventors' firstproposal, this would be effective to reduce the H₂S content down to 5ppm or less, but it is possible that there would be some precipitatesand/or scaling formed or deposited on surfaces of the tanker truck orother vessel transporting the crude oil, which would be undesirable.

According to the inventors' second recent proposal, an appropriateamount of organic acid(s) such as fulvic acid and humic acid is alsoadded to the treated liquid at a dosage rate that will typically resultin a concentration of the organic acid(s) in the liquid being treatedbeing in a normal range of 0.01-10 ppm, preferably 0.1-3 ppm, whetherthe liquid is a hydrocarbon based liquid or contaminated aqueoussolution. Within such range, the most appropriate dosage rate of theorganic acid(s), like the most appropriate dosage rate of the firstrecently proposed treatment solution, largely depends on: 1) the amountof H₂S and other sulfur containing contaminants in the liquid beingtreated; 2) the viscosity of the liquid; and 3) the amount of timepermitted for reacting the treatment solution with the liquid beingtreated, although heating and/or mixing of the liquid being treated willreduce the viscosity of the liquid and will also reduce the amount oftime required for properly remediating the H₂S and other contaminants inthe liquid. The dosage amount of organic acid(s) is substantially,linearly scalable within the discussed range based on these factors.Additionally, a small amount of monoethanolamine or MEA (C₂H₇NO) may beadded to the treated liquid, along with the organic acid(s), e.g., anamount corresponding to a concentration of 0.5-15 ppm, and preferably1.0-10 ppm, of the MEA in the hydrocarbon based liquid or aqueoussolution being treated. The small amount of MEA acts as an anti-scalingagent in the second proposed treatment process/composition. Forconvenience, the additional components, including the organic acids andMEA may be combined with the treatment solution according to theinventors' first proposal. e.g., in the modified treatment solution theat least one organic acid may constitute 0.1-5 wt % of the modifiedtreatment composition and MEA may constitute 0.05-2 wt % of the modifiedtreatment composition.

Fulvic acid is actually a family of organic acids, but may typically beidentified as 1H,3H-Pyrano[4,3-b][1]benzopyran-9-carboxylic acid,4,10-dihydro-3,7,8-trihydroxy-3-methyl-10-oxo-;3,7,8-trihydroxy-3-methyl-10-oxo-1,4-dihydropyrano[4,3-b]chromene-9-carboxylicacid, with an average chemical formula of C₁₃₅H₁₈₂O₉₅N₅S₂ and molecularweights typically in a range of 100 to 10,000 g/mol. Somewhat similarly,humic acid is a mixture of several molecules, some of which are based ona motif of aromatic nuclei with phenolic and carboxylic substituents,linked together, and the illustration below shows a typical structure.Molecular weight (size) of humic acid is typically much larger than thatof fulvic acid, and can vary from 50,000 to more than 500,000 g/mol.

In the treatment process according to the inventors' second proposal theorganic acid(s) which are also added to the liquids being treated assurethat substantially no precipitate(s), scaling or the like will be formedfrom the treated liquids while they are being treated, transportedand/or stored for a period of time such as hours, days or weeks.Further, to any extent that there is a increased likelihood thatprecipitate(s), scaling or the like may be formed in a treated liquid,e.g., the treated liquid contains an especially high content of H₂S andother sulfides requiring a larger dosage of the treatment solutionaccording to the inventor's recent proposal and/or the liquid beingtreated contains a high content of rag components such as organicmatter, an increased amount of the organic acid(s) may be added to thetreated liquid beyond the normal range of 0.01-10 ppm to assure thatsubstantially no precipitate(s), scaling or the like will be formed.

The inventors' recently proposed treatment processes may be convenientlycarried out essentially wherever the contaminated liquids may bepresent, e.g., in open bodies of the liquids, in conjunction with atransport tanker or other vessel in which the liquids are beingtransported, at a wellhead where the liquids are being extracted fromthe ground, in open or closed tanks, in an enclosed pipeline throughwhich the contaminated water or other liquid is being transported, etc.

While the known treatment methods and compositions for remediatingsulfur-containing compounds, including H₂S, from fluids includinghydrocarbon based liquids, aqueous solutions, natural gas and mixturesof two or more these fluids especially the methods and treatmentcompositions according to the present inventors' recent proposals aregenerally effective for remediating the H₂S and other contaminants inthe liquids, they remain to be improved on, especially in relation totreated contaminated gasses and treating mixtures of contaminatedliquids and gasses.

For example, the present inventors' recently proposed treatment methodsand compositions cannot be similarly applied in relation to treatment ofcontaminated gasses such as natural gas as the nature of remediation ofthe contaminants is more complicated. Such contaminated gasses oftencontain significant amounts of other contaminants in addition to H₂S,e.g., carbon dioxide (CO₂), nitrogen (N₂), water (H₂O), sodium chloride(NaCl), etc. It is desirable that all or most of these contaminants beremediated as the gas is withdrawn from the well, or within a short timethereafter, although a final remediation may be performed at a refineryor the like. Of course, the nature of natural gas is much different fromthe nature of crude oil and other liquids, including that natural gas istypically, continuously discharged from a well at significantvelocities, pressures and volumes, it is handled and processed muchdifferently than liquids, the value of natural gas on volume basis ismuch less than crude oil, etc., and this creates additionalcomplications for treating contaminated gasses. For example, a typicaloil well will discharge 5 to 30,000 barrels of crude oil and 1-20million ft³ of natural gas/day. Further, with contaminated liquids thetime involved in a treatment process for remediation of contaminants maybe an hour or more, but this is typically not a problem as the treatmentcomposition may be simply mixed or provided with the contaminated liquidand then let sit for the time required for the H₂S and othercontaminant(s) in the liquid to be remediated. On the other hand, atreatment process for remediating a contaminated gas such as natural gasmay only permit contact between the treatment composition and thecontaminated gas for a few seconds. Further, some of the contaminants inthe natural gas may tend to generate significant amounts ofprecipitates, which can greatly affect the treatment process. In fact,the natural gas extracted from many existing wells around the world areso highly contaminated with H₂S, as well as other contaminants includingwater, salts, CO₂, etc., that conventionally known treatment processesand treatment compositions for treating the natural gas to remediate thecontaminants therein are not sufficiently effective and/or efficient,whereby it has been economically impractical to treat such highlycontaminated natural gas so that it may be sold and used. While somestates and nations previously permitted the highly contaminated naturalgas to be simply burned/flared as it is extracted from the wells, inorder to extract the crude oil that is discharged from the wells alongwith the natural gas, many states and nations no longer permit suchburning/flaring of the contaminated natural gas due to environmentalconcerns. Hence, many existing wells now remain capped and idle, whichis astonishing as the cost of drilling and establishing a typical oilwell may be 10 million dollars or more.

Again, a typical oil well may discharge 5 to 30,000 barrels of crude oiland 1-20 million ft³ of natural gas/day, as well as 200,000-250,000barrels of contaminated water as a mixed fluid. Many oil wells will havea 3-way separator provided in association therewith which separatesthese three fluids into a gas phase, a hydrocarbon liquid phase and anaqueous liquid phase, whereby the crude oil and the natural gas mayseparately output from the separator for treatment. e.g., the crude oilmay be sent by truck and/or pipeline to a refinery and natural gas maybe sent by pipeline to a refinery. Typically, such pipelines willrestrict acceptance of the crude oil and natural gas based on thecontent of H₂S contained therein being at or below a predetermined levelbecause H₂S can be very corrosive-damaging to the pipelines. However,some oil wells have a two-way separator associated therewith, ratherthan a three-way separator, and the two way separator jointly outputsnatural gas and crude oil as one output for further processing andcontaminated water as the other which may be disposed of by injectingback downhole into the earth. Further, the pipelines that handle amixture of crude oil and natural gas may be formed of specialty steelsand other materials which can accept a much higher content of H₂Scontained in the mixed fluid, e.g., the content may be as high as 20,000ppm. For such contaminated, mixed fluids, it still remains a challengein the art for reducing content of H₂S

Thus, there remains in the art a need for treatment systems, treatmentmethods and treatment compositions for remediating contaminants such asH₂S, other sulfur based contaminants, CO₂, salts, water, N₂, etc., influids, including liquids such as crude oil and contaminated waterextracted from the earth with crude oil, contaminated natural gas andother gasses, and mixtures of two or more of such fluids, where thetreatment systems and methods are practical in terms of effectivenessand cost. There is a need for such treatment systems, methods andcompositions which are improved in terms of effectiveness in completelyremediating the contaminants down to government regulated levels orlower, as well as in terms of efficiency in quickly remediating thesulfide compounds and other contaminants at a reasonable cost, and withgood flexibility in the ability to perform the treatment method atessentially any location, including directly at a well head or an oilfield where crude oil or natural gas is being extracted.

SUMMARY OF THE INVENTION

An object of the present invention is to satisfy the discussed need.

Treatment of Contaminated Gasses

The present inventor has carefully investigated caustic treatment ofpetroleum based gasses including natural gas, as well as othercontaminated gasses for removing H₂S and other contaminants therefrom,and has discovered some new treatment systems, methods and compositionsfor efficiently remediating the contaminants in such gasses.

One discovery made by the present inventor is that when his previouslyproposed treatment compositions are used for treating a large volume ofa highly contaminated gas which is flowing, e.g., natural gas which isbeing extracted from well and which contains significant amounts of H₂Sand other contaminants, simply flowing/bubbling the contaminated gasthrough the treatment compositions may not be an efficient or practicalmethod for remediating the contaminants. While the inventor's previouslyproposed treatment solutions are effective for remediating the H₂S andother contaminants in the gasses down below government accepted levels,the treatment solutions and the treatment processes may become much lesseffective in a relatively short time, such as 4-12 hours of use, due toother contaminants in the natural gas besides H₂S and to the nature ofthe treatment process for natural gas. This makes the cost of thetreatment process itself very high in terms of the treatment solutionhaving to be replaced every 4-12 hours, as well as shutting down andrestarting the process every few hours. Moreover, it is no simple,inexpensive task to stop and re-start the flow of natural gas and otherfluids from a well.

In relation to the discovery, one of the inventors has discovered thatthere are multiple complications involved with the problem. A maincomplication is that some of the contaminants in the natural gas, suchas Na and Cl ions from salts, may generate significant amounts ofprecipitates that released from the natural gas as it is being treatedand clog up components of the treatment system and the treatmentprocess. For example, if natural gas contains a significant amount ofsodium chloride (NaCl), e.g., any water vapor contained in the naturalgas will typically be saturated with Na and Cl ions and these ionscombine as sodium chloride NaCl which tends to precipitate out of thenatural gas as it is being treated and quickly build up to a significantamount in 1-6 hours. Such precipitates tend to greatly disrupt thetreatment process and would have to be removed on a regular basis,again, making the treatment process more complicated and inefficient.Such precipitation of sodium chloride occurs even if the treatmentprocess uses a treatment solution according to the inventor's proposalin PCT/US2018/064015, which includes an organic acid such as fulvic acidor humic acid that helps to prevent formation of precipitates in treatedliquids/fluids. Another complication is that some of the contaminantsinterfere with remediation of the H₂S and other targeted contaminants,inhibiting and slowing down the remediation and requiring additionaltreatment composition to be used to achieve the desired level ofremediation. Still another complication is the nature of the natural gaswhich is to be treated with a liquid treatment composition, and thevelocity, pressure and volume at which natural gas is discharged from awell. For the contaminants that are to be remediated, including H₂S,there must be sufficient contact between the contaminants and thehydroxides and other reactants in the treatment composition and this isvery difficult or impossible to achieve if the natural gas is flowing ata high velocity, such 10 feet/sec. or more.

The inventor has further studied the treatment of contaminated gasses inlight of the discovered complications, and the inventor has furtherdiscovered novel treatment systems, treatment processes and treatmentcompositions that address and overcome each of the complicationsdiscussed above and provide a very practical, effective and efficientmanner of remediating contaminated natural gas and other contaminatedgasses.

According to an aspect of the present invention, the inventor hasdetermined that the first complication pertaining to formation andrelease of precipitates may be overcome by initially treating thecontaminated gas to remove the contaminants most likely to generateprecipitates, including Na and Cl ions. This may be done, for example,by passing the contaminated gas through a water wash flow cell ofpotable water to remove such ions which are very soluble in water. Theinventor has performed testing of the effects of a water wash flow cellon contaminated natural gas obtained from a well, after the natural gasis initially separated from the crude oil and contaminated water that isdischarged with the natural gas from the well, and has found that thewater wash very effective for removing these contaminants from thecontaminated gas, e.g., testing showed that the after the water wash thegas contained an undetectable amount of Na and less than 0.03 ppm of Cl.Removal of the contaminants most likely to generate precipitates,including Na and Cl ions, not only prevents formation of precipitates,but the inventor has also discovered that it also synergisticallyimproves the efficiency of the treatment composition that remediates H₂Sand CO₂ according to an embodiment of the present invention as discussedfurther herein.

According to another aspect of the present invention, the inventor hasdetermined that the second complication pertaining to interference toremediation of primary targeted contaminants including H₂S by othercontaminants in the gas may largely be overcome by also removing most ofthe water (H₂O) in the natural gas before the treatment for remediationof H₂S and other targeted contaminants. Generally, contaminated naturalgas from a well may contain trace amounts of water up to 5% volume, andafter passing through a water wash flow cell the natural gas willtypically contain at least 2% volume of water. It is possible to removewater from the natural gas using a variety of conventional means. e.g.,a glycol tower, a coalescing or dehydrating unit which causes watervapor in the gas to liquefy and drop out, etc. The conventional meansmay be appropriate for use according to the exemplary embodiments of thepresent invention, but the inventor has determined that it is importantto reduce the water content to a very low level. e.g., less than 1 ppm,and more preferably ≤0.5 ppm in the natural gas, because even low levelsof water can add up to significant quantities over a period of 24 hours(one day) in the treatment of natural gas flowing from a well, and thewater will, among other things, dilute the treatment composition whichremediates H₂S and other targeted contaminants according to theexemplary embodiments of the present invention, and this undesirablymakes the treatment process less efficient by increasing necessaryreaction times, etc. For example, with an average size well dischargingabout 2 million ft³ of natural gas/day at 125-150 PSI, if the naturalgas contains 2 ppm of water, this amounts to more than 7 barrels ofwater/day in the natural gas, whereas in the exemplary treatment processaccording to an embodiment of the invention the amount of treatmentcompositions used may be less than one barrel.

Additionally, because water is one of the byproducts resulting fromremediation of H₂S and other targeted contaminants using the exemplarytreatment compositions according to the exemplary embodiments of thepresent invention, the inventor has further determined that it is alsovery beneficial to remove water from treatment compositions being usedin the reactor throughout the treatment process in order to achieve evenbetter efficiency. The water can be removed periodically, e.g., when theamount of water in the treatment composition reaches a predeterminedlevel, or continuously. For example, some amount of the treatmentcomposition may form a pool in a bottom portion of a reaction chamber ofthe reactor and from that pool some amount, e.g., 1-20% volume, may bewithdrawn and heated to a temperature at which the water will vaporizebut which does not otherwise adversely affect the treatment composition.e.g., 240-400° F. the evaporated water can be drawn off and then thedehydrated treatment composition returned to the reaction chamber.

According to another aspect of the present invention, the inventor hasdetermined that the third complication, pertaining to the nature of thenatural gas which is to be treated with a liquid treatment compositionand the high rate at which natural gas is extracted from a well, maylargely be overcome by: regulating the pressure of the natural gas to anappropriate level which will correspond to a flow rate or velocity ofthe natural gas being remediated to less than 10 feet/sec, preferably to≤5 feet/sec, as it passes through one or more reactors sufficientlysized to handle all of the gas being discharged from the well; anddisrupting the flow of the natural gas through the reactor(s) so thatthe gas cannot flow uninterrupted therethrough in a stream or as largebubbles, and will thereby have much more surface area for reacting withthe treatment composition. Such disruption may be accomplished bypacking the reactor(s) or portions thereof with a fine, non-reactivemedia, e.g., stainless steel wool, pea gravel, perforated plates, etc.,through which the natural gas will pass as it flows through thereactor(s). Additionally, the inventor has determined that for optimumefficiency, it is desirable that the reactor should not be filled to anyextent with the treatment composition. e.g., as a bubble tower, butinstead may be operated as a counter-flow type reactor in which thenatural gas is continuously introduced near the bottom of the reactorand the treatment composition is continuously introduced at intermediateand/or upper portions of the reactor so as to wet or saturate thenon-reactive media and so that the natural gas will contact and reactwith the treatment composition as it flows upward through the reactor.With such a counter-flow reactor, some of the treatment composition willremain in the treated natural gas along with the remediated contaminantsas the natural gas exits the reactor, and some of the treatmentcomposition may descend to a bottom portion of the reactor andaccumulate based on gravity. The amount of treatment compositionremaining in the natural gas as it exits the reactor may be minimized byproviding some type of baffle, e.g., perforated plate(s), before thereactor exit that the natural gas will contact and which will separateany small droplets of treatment composition from the natural gas andpermit same to drip back down into the reactor. The amount of treatmentcomposition which descends into and accumulates at the bottom portion ofthe reactor may be used as the source for withdrawing some of thetreatment composition to be dehydrated by removing accumulated water,which dehydrated composition may then be re-circulated back into thereactor as discussed herein.

According to another aspect of the present invention, based on asubstantial amount of experimentation the present inventor hasdiscovered a new treatment composition that works exceptionally well forremediating H₂S and other targeted contaminants typically contained innatural gas extracted from the earth. The new treatment compositionincludes some components that are also in the previously proposedtreatment composition disclosed in PCT/US2018/064015 for treatingcontaminated liquids such as crude oil, and these components performsimilar functions when treating the contaminated natural gas. Forexample, a concentrated aqueous hydroxide solution with 35-55 wt % ofone or more hydroxide compounds is used as the main component, e.g., atleast 80 wt % and preferably at least 90 wt %, of the new treatmentcomposition, and the aqueous hydroxide solution reacts with andremediates H₂S and other targeted contaminants in the contaminatedgasses as it does with these same targeted contaminants in liquids suchas crude oil and contaminated water extracted with the crude oil asdiscussed in PCT/US2018/064015. Additionally, the new treatmentcomposition may include a small amount, e.g., 0.1-3 wt % of an organicacid such as fulvic acid or humic acid which functions to prevent anyprecipitates from being generated and released from the treated gasses.Additionally, the new treatment composition according to an exemplaryembodiment of the present invention may also include, for example, asmall amount, e.g., 0.1-5 wt %, of a chelating agent such asethylenediaminetetraacetic acid or EDTA (C₁₀H₁₆N₂O₈), which among otherthings helps to improve molar reactivity of the hydroxide compound(s)and helps to prevent formation of precipitates, and smaller amounts of asurfactant and a buffering agent.

Although some prior treatment compositions and treatment systems forremoving H₂S and other sulfur based contaminants in crude oil andnatural gas include use of metals-metal ions for bonding to the bondingthe sulfur based contaminants and generating precipitates that can beremoved from the treated fluids, the treatment compositions according tothe present invention preferably do not include metals-metal ionsbecause it is intended that the remediated sulfur compounds will remainin the treated fluids without forming any precipitates that are removedfrom the treated fluids. Ultimately, if and when the treated fluids aretreated at a refinery, as is typical with many of the treated fluids,the remediated contaminants and any excess-unused treatment compositionmay be removed from the fluids. However, if the treated fluids were tocontain metals-metal ions, e.g., zinc, copper, iron, manganese, etc.,the metals-metal ions may have a very detrimental effect on the refineryprocesses, e.g., they may poison and otherwise damage the catalysts usedin the refinery processes. Hence, it is preferred that no metals-metalions are used in the treatment compositions according to the presentinvention.

Relative to the hydroxide compound(s) used in the treatment composition,it is preferable to use only hydroxide compound(s) which do not containelement(s)/component(s) that are also included as a significantcontaminant in the gas being treated. For example, if the gas contains asignificant amount of sodium chloride as a contaminant, then thehydroxide compound(s) in the treatment solution should be other thansodium hydroxide (NaOH), e.g., potassium hydroxide (KOH), lithiumhydroxide (LiOH), magnesium hydroxide (Mg(OH)₂), and manganese hydroxide(Mn(OH)₂, Mn(OH)₄) would be suitable hydroxides for use in thissituation. Of course, with the Na and Cl ions being initially removed inthe water wash, it would be possible to use sodium hydroxide as ahydroxide compound in the treatment solution. Also, ammonium hydroxide(NH₄OH) may be used in the treatment compositions according to thepresent invention, and may have some particular benefits associatedtherewith as discussed further herein. However, there are limits to howmuch ammonia (NH₃) may be included in fluids such as crude oil andnatural gas, e.g., natural gas should not have more than 14 ppm ammonia,so that it would be important to limit the amount of ammonium hydroxideincluded in the treatment compositions such that the treated fluids donot contain excessive amounts of ammonia.

Relative to the carbon dioxide (CO₂) in the natural gas, this can beremediated with the hydroxide compound(s) in the treatment compositionaccording to the exemplary embodiment of the invention, andtheoretically this would require an additional amount of the treatmentcomposition to be used in the remediation process. For this reason, oneof the present inventors considered the possibility of removing CO₂ fromthe natural gas before it is treated with the treatment composition inthe counter-flow reactor, e.g., by a scrubbing process, or by additionof carbonate compounds in the treatment composition to reduce reactivityof hydroxides in the treatment composition with CO₂. However, theinventor further discovered that when the Na and Cl ions are initiallyremoved from the natural gas using the water wash and because thetreatment composition is highly basic with a pH of 13-14, such that thepH of the natural gas is increased from an initial value of about5.8-6.2 to a pH of at least 7 when it contacts the treatmentcomposition, this has a synergistic effect whereby some of the H₂S andCO₂ in the natural gas react together to form, among other things,hydroxide ion OH⁻, which will then help to efficiently remediate otherH₂S and CO₂ in the natural gas. Hence, while is possible to initiallyscrub CO₂ from the natural gas before the gas is remediated using thetreatment composition of the present invention or to add carbonates tothe treatment composition to reduce reactivity with CO₂, the treatmentprocess according to the present invention can efficiently remediate theCO₂ content in the natural gas down to 1 ppm or less without separatelyscrubbing the CO₂ using an additional scrubbing process or addingcarbonates to the treatment composition.

With the new treatment composition according to the exemplary embodimentof the present invention as used in a treatment system and processaccording to the above discussed aspects of the present invention,including a water wash flow cell to remove Na, Cl ions, a device forinitially removing water from the natural gas, and a counter-flowreactor, the present inventor has successfully remediated the H₂S andother targeted contaminants in natural gas, including mercaptans,thiophene and other disulfides. H₂O. CO₂. NaCl and nitrogen (N₂) down toless than 1 ppm each in a small scale operation, and without generationof any precipitates from the treated natural gas in the counter-flowreactor. It is expected that in a full scale operation, e.g., includinga counter-flow reactor with a 2 ft ID and 21 ft tall, and at least 6 ftof which is packed with non-reactive media, a continuous flow of naturalgas from a well at 2 million ft³/day, including 2,000-100,000 ppm H₂Sand other contaminants may be successfully treated down to less than 1ppm for each of the contaminants by regulating the pressure of the gaswithin a range of 50-250 psi to assure that the gas flows at less than10 feet/second, and preferably ≤5 feet/second, and using 1-4gallons/hour or 24-96 gallons total/day of the treatment compositionaccording to the exemplary embodiment. Overall, such a treatment processis practical because it is very effective and cost efficient forremediating even highly contaminated natural gas, unlike all known,conventional treatment processes existing prior to the presentinvention. The natural gas as treated using the treatment compositionand treatment process according to the exemplary embodiment of thepresent invention is so clean, that it may be directly sold as sweetnatural gas without further processing. Similarly, it may be directlycondensed into liquefied petroleum gas (LPG) in the vicinity of the wellfrom which it is extracted. In such liquefied state the gas may be veryeconomically stored and transported. While a vertically extendingcounter-flow reactor is used in the above treatment process, other typesof reactors may also be used, e.g., reactors that extend horizontally ordiagonally may also be used.

Modifications to the Gas Treatment Composition and/or Treatment Process

As discussed herein one important aspect of the treatment process forremediating a contaminated gas, such as natural gas from a well, is theflowrate of the gas as it passes through a quantity of treatmentsolution as contained in a reaction chamber or the like, e.g., the flowrate should be less than 10 ft/sec and preferably ≤5 feet/sec., and thedesired flowrate may be achieved by appropriately adjusting the size ofthe reaction chamber through which a given volume of the gas flows/unittime and/or appropriately adjusting the pressure of the gas. In thisregard, the present inventors have discovered an unusual and unexpectedadditional benefit that may be achieved when the pressure of the gas isincreased or adjusted using a compressor as part of the treatmentprocess.

The inventors have discovered that when a compressor is used to increasethe pressure of contaminated gas after the gas has passed through awater wash flow cell of potable water to remove ions of salt moleculesand the like, and before the gas is further processed to remove waterand to be remediated in a reactor using a treatment compositionaccording to the present invention, it is possible to achievesignificant remediation of the H₂S and CO₂ contaminants by introducingan amount of the treatment composition according to the presentinvention into the gas before and/or after it is compressed by thecompressor. For example, in an actual treatment process according to thepresent invention involving treatment of contaminated natural gas from awell at a rate of 1,000,000 ft³/day, wherein the gas contained 80,000ppm of H₂S and 160,000 ppm of CO₂, an amount of a treatment compositionaccording to the present invention was added to the water used in thewater wash flow cell prior to passing the gas through the water washflow cell in order to increase the pH of the water to be within a rangeof 13-14. The amount of treatment composition added to the wash waterwas much less than the amount of treatment composition which would beused in the counter flow reactor or other reactor for specificallyremediating the H₂S and CO₂ contaminants in the natural gas and it isotherwise significantly diluted by the wash water, but would nonethelesshave some positive effect in remediating some amount of the H₂S and CO₂contaminants as the natural gas passed through the water wash. However,the inventors were very surprised to discover that by adding thecompressor as part of the treatment system, after the water wash flowcell, for increasing the pressure of the natural gas at this stage inthe treatment process, the actions of compressing the natural gas toincrease its pressure. e.g., by 50 to 100 psi up to a total of 170-220psi, the content of H₂S in the natural gas was reduced by approximately20,000 ppm to around 60,000 and the content of CO₂ in the natural gaswas reduced by approximately 40,000 ppm to around 120,000 ppm. Althoughthe inventors do not yet fully understand why or how the actions of thecompressor achieved this significant reduction in H₂S and CO₂contaminants, it is believed to involve the relatively small amount oftreatment composition picked up by the natural gas as it passed throughthe water wash flow cell reacting with these contaminants based on thecompression and expansion of the gas, and a corresponding temperatureincrease, as it is compressed by the compressor to the higher pressureand then expanded to some extent as it is released from the compressorback into the system piping leading from the compressor to othercomponents of the system.

Based on this unexpected result, the inventors further experimented byintroducing additional amounts of the treatment composition according tothe present invention in an atomized form into the natural gasimmediately before it is received by the compressor and immediatelyafter it is discharged by the compressor. The additional amounts of thetreatment composition introduced into the natural gas in each of theseexperiments was approximately 1.4 gallons/hour for the gas which wasflowing at a rate of 1,000,000 ft³/day. The additional amount of thetreatment composition added into the natural gas immediately before itwas received by the compressor resulted in a further small reduction ofthe H₂S and CO₂ contaminants, but not enough to justify the additionalcost of the additional treatment composition and the additional processstep. On the other hand, the additional amount of the treatmentcomposition added into the natural gas immediately after it wasdischarged by the compressor very surprisingly resulted in a completereduction of the H₂S and CO contaminants down to approximately 0 ppm.Due to such surprising result, it was not necessary to further treat thenatural gas in the remaining components/steps of the treatmentsystem/process according to the present invention as there was nofurther H₂S and CO₂ to remediate. Of course, if desired the gas could befurther treated for removing other contaminants, including water and anysalt ions not removed in the water wash. As with the normal treatmentprocess using the treatment composition according to the presentinvention whereby H₂S and CO₂ are remediated by reacting with thetreatment composition, such reactions are advantageously non-reversibleso that the sulfur compositions remaining in the remediated natural gasdo not revert to H₂S to any appreciable extent.

As discussed herein, one of the significant complications involved inremediating H₂S and CO₂ in contaminated gases such as natural gaspertains to formation and release of precipitates such as salts from thetreated gases because the precipitates may readily clog up the treatmentsystem and make it inefficient and impractical, and that one solution tosuch complication as provided by the present invention is to initiallytreat the contaminated gas to remove the contaminants most likely togenerate precipitates, including Na and Cl ions, using a water wash flowcell or the like. According to the present invention, another possiblesolution to this significant complication is to provide a treatmentcomposition which selectively targets specific contaminants forremediation including H₂S and CO₂, but which does not significantlyreact with other contaminants such as Na and Cl ions and does not causethese other contaminants to form precipitates which are released fromthe treated gases.

Particularly, according to another aspect of the present invention theaqueous based treatment composition including hydroxide compound(s),organic acid(s) such as fulvic acid and humic acid, and a chelatingagent such as EDTA is modified by being combined or mixed with ahydrocarbon based liquid and then the modified treatment composition isused to remediate specific contaminants including H₂S and CO₂ accordinga treatment process of the present invention. For example, as discussedherein the aqueous treatment composition according to an embodiment ofthe present invention may be a concentrated aqueous hydroxide solutionwith 35-55 wt % of one or more hydroxide compounds is used as the maincomponent, e.g., at least 80 wt % and preferably at least 90 wt %, ofthe new treatment composition, together with 0.1-3 wt % of an organicacid such as fulvic acid or humic acid and 0.1-4 wt %, of a chelatingagent such as EDTA. A quantity of such treatment composition may bemodified by being thoroughly combined or mixed with a quantity of ahydrocarbon based liquid, which may be refined or not refined and mayhave an API rating in a range of about 30-50. For example, a refinedhydrocarbon based liquid that may be used is #1 diesel fuel, #2 dieselfuel or off road diesel fuel. The quantities of the aqueous basedtreatment composition and the hydrocarbon based liquid which arecombined may be substantially equal, but could be modified to includemore or less of either component, e.g., the total mixture may contain 40volume % of the aqueous based composition and 60 volume % of thehydrocarbon based liquid, 60 volume % of the aqueous based compositionand 40 volume % of the hydrocarbon based liquid, etc. Specific gravityof the aqueous composition may be around 1.4 and specific gravity of thehydrocarbon based liquid may be around 0.98 and specific gravity of theblended mixture will be somewhere in between these values.

The blended, modified treatment composition is essentially an alkalineoil with a pH of about 14, although the aqueous and hydrocarbon basedportions of the mixture do not completely blend together to form astable, homogeneous mixture and will separate from each other if leftundisturbed for a length of time. Again, the chemical compounds in thealkaline aqueous portion of the modified treatment composition willmitigate the H₂S and CO₂ in the gas stream similarly to the unmodifiedtreatment composition, so the main challenge is to prevent othercontaminants such as salts ions from reacting with the chemicalcompounds to form precipitates. Another concern, as discussed herein, isthat H⁺ ions from H₂S may react with the hydroxide compound(s)generating H⁻ that then reacts with the chloride ions creatinghydrochloric acid (HCl), which in turn reacts with the hydroxidecompound(s) in the treatment composition to undesirably use up thehydroxide compound(s) at a faster rate than expected, and which mayundesirably lower the pH or raise the PKa of the treatment composition.Although the exact mechanisms involved may not be fully understood, themodified treatment composition is believed to work as follows inremediating contaminants such as H₂S and CO₂ in the contaminated gases.First, because the pH of the modified treatment composition is about 14,undesired formation of HCl is avoided and the hydroxide compound(s) inthe aqueous portion of the treatment composition may efficientlyremediate the H₂S and CO₂ similarly to the unmodified treatmentcomposition in that the H₂S and CO₂ are in gaseous phase and may bedirectly contacted by and react with the chemical compounds in themodified treatment composition even though the chemical compounds aremixed with the hydrocarbon based liquid in the modified composition. Onthe other hand, the salt ions that tend to cause precipitates are not ingaseous phase, but are in the water vapor in the natural gas streambeing treated due to the high solubility of these ions in the water.Further, because the hydrocarbon based portion of the modified treatmentcomposition is not miscible with the water vapor this effectivelyprevents the chemical compounds in the modified composition fromreacting with the salt ions in the water vapor, and hence preventsformation of precipitates. In other words, the hydrocarbon based portionof the treatment composition effectively acts as a buffering agent thatprevents the modified treatment composition from reacting with the saltions to form precipitates, even though the chemical compound is able toremediate the H₂S and CO₂ in the gas stream. The present inventors haveconducted testing on a contaminated natural gas stream that has beentreated using the modified treatment composition according to thepresent invention and the testing shows that the water vapor and saltions are still in the water vapor in the treated gas stream aftertreatment.

Treatment of Mixed Contaminated Fluids Including Liquid and Gas

The present inventors have carefully investigated treatment of mixedcontaminated fluids including both liquid and gas, and have alsodiscovered a new treatment system and methods for efficientlyremediating the H₂S and other contaminants in such fluid mixturescontaining both contaminated liquid and contaminated gas using treatmentcompositions such as disclosed in PCT/US2018/064015 and variationsthereof as discussed herein.

One discovery made by the present inventors is that when the treatmentcompositions are used for treating a continuously flowing, large volumeof a fluid mixture highly contaminated with H₂S and other contaminants,e.g., a continuously flowing mixture of crude oil and natural gas from awell, such fluid mixture may be efficiently and effectively treated forremediation of the H₂S and other contaminants by continuously adding atreatment composition. The treatment composition may be one of thosedisclosed in PCT/US2018/064015 and modifications thereof as discussedherein including a chelating agent and possibly a surfactant. Thetreatment composition is added to the contaminated fluid mixture at apredetermined dosage rate directly, e.g., after the mixed fluid isextracted from a well and passed through a two way separator to removeall or most of the aqueous portion of the mixed fluid leaving only thecrude oil and natural gas. Then as the fluid mixture of crude oil andnatural gas continues to flow in a pipeline toward another pipeline thatwill send the fluid mixture to a refinery, e.g., typically for manymiles and over a period of hours, the treatment composition will reactwith and remediate the H₂S and other contaminants in both the liquid andgaseous components of such fluid mixture such that the content of thesecontaminants will be reduced to appropriate levels by the time the fluidmixture arrives at the pipeline leading to the refinery. The crude oilfunctions as a carrier medium for the treatment composition, but thereis still significant reaction between the H₂S and other contaminants inthe natural gas and the treatment composition in the crude oil. Veryimportantly, essentially no precipitates will be discharged from thetreated mixed fluid as it passes through the pipeline and is thecontaminants therein are remediated. Discharge of any amount ofprecipitate(s) from the treated fluid is very undesirable as theprecipitates may partially or completely clog the pipeline, and wouldrequire the pipeline to be shut down for corrective action. Theinventors have determined that even if the contaminated fluid mixturecontained a relatively high content of H₂S when it was discharged fromthe separator, e.g., 40,000 ppm or higher, the content of the H₂S in theliquid portion of the mixture, e.g., crude oil, may be reduced downbelow 5 ppm and the content of the H₂S in the gaseous portion of themixture, e.g., natural gas, may be reduced down below 20,000 ppm.

For purposes of effecting such treatment process, the present inventorshave determined that one appropriate system that may be used involve useof a reactor that extends horizontally or diagonally rather thanvertically. In such reactors the oil and natural gas mixture from theseparator continuously flows into a lower portion of the reactor, anappropriate amount of the treatment composition is added to the fluidmixture before the fluid mixture enters the reactor and/or to the fluidmixture in the reactor so as to achieve a desired concentration of thetreatment composition/unit volume of the fluid mixture. Some of thefluid mixture as combined with the treatment composition is continuouslywithdrawn from an upper portion of the reactor, and the withdrawnportion will then flow along a pipeline toward another pipeline thatwill send the fluid mixture to a refinery giving time for the treatmentcomposition to react with and remediate the H₂S and other contaminantsin the fluid mixture. Given that the fluid mixture being treatedcontains a significant amount of gas, one appropriate manner of flowingthe fluid mixture into the reactor is via numerous small openings formedin pipe(s) extending longitudinally or diagonally along the lowerportion of the reactor, whereby the fluid mixture will enter the reactorin the form of small fluid streams containing bubbles of the gas thatcause the fluid streams to flow upward through other fluid already inthe reactor so as to mix with the same, and the fluid mixture beingwithdrawn from the upper portion of the reactor will have a generallyhomogeneous-consistent content of the treatment composition. Forcontinuously adding the treatment composition to the reactor, theconcentration of the treatment composition in the mixed fluid beingwithdrawn from the reactor may be monitored to determine if the rate ofat which the treatment composition is being added needs to be adjusted,while a portion of the mixed fluid in the reactor may be continuouslywithdrawn from a bottom portion of the reactor, mixed with additionaltreatment composition and then again flowed into the reactor along withadditional mixed fluid from the separator.

Again, the present inventors have discovered that for such treatmentsystem and process, treatment compositions such as disclosed inPCT/US2018/064015 and variations thereof as discussed herein, areappropriate for treating the contaminated fluid mixture.PCT/US2018/064015 discloses a concentrated aqueous hydroxide solutionwith 35-55 wt % of one or more hydroxide compounds as the maincomponent, e.g., at least 80 wt % and preferably at least 90 wt %, ofthe new treatment composition, together with a small amount, e.g., 0.1-3wt % of an organic acid such as fulvic acid or humic acid, and possiblya small amount of MEA, e.g., 0.1-3 wt %, and perhaps an antibacterialcompound such as potassium silicate. The concentrated hydroxidecompound(s) react with H₂S and other sulfur based contaminants toremediate same, while the organic acids such as fulvic acid and humicacid function to prevent any precipitates from being generated andreleased from the treated fluid, and MEA functions as an anti-scalingagent. On the other hand, modifications to the treatment compositiondisclosed herein may also be an aqueous solution primarily including ahigh concentration of hydroxide compound(s), e.g., 35-55 wt % of one ormore hydroxide compounds as the main component, e.g., at least 80 wt %and preferably at least 90 wt %, of the treatment composition, togetherwith a small amount, e.g., e.g., 0.5-6 wt %, ofethylenediaminetetraacetic acid or EDTA (C₁₀H₁₆N₂O) which is a type ofchelating agent that, among other things, helps to improve molarreactivity of the hydroxide compound(s) and helps to prevent formationof precipitates, and possibly smaller amounts, e.g., 0.01-0.1% volume,of a surfactant such as sodium lauryl sulphate and a buffering agentsuch as potassium carbonate, etc.

An appropriate amount of such treatment compositions will, of course, bebased on amount of the mixed fluid being treated. For a typical oil wellwith well head piping having a diameter of 2-10 inches and an output of5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ ofnatural gas/day (24 hours) and wherein the H₂S content of the mixedfluid at 40,000 ppm or higher, the inventors have found that anappropriate amount of treatment composition is in a range of 5 to 20gallons of treatment composition added per hour or 120-480 gallons perday. The inventors have determined that under these conditions thetreated crude oil in the mixed fluid will have less than 5 ppm H₂S andoften 0 ppm H₂S, while the treated natural gas in the mixed fluid willhave less than 20,000 ppm H₂S, which is appropriate to make the gasacceptable for the pipeline to the refinery.

Another modification to the treatment composition which the presentinventors have determined may be used for treating a contaminated mixedfluid of crude oil and natural gas involves use of a concentratedaqueous, ammonium hydroxide (NH₄OH) solution, e.g., 25-35 wt %, togetherwith or as one of the hydroxides in the composition. For example, amodified treatment composition may be a concentrated aqueous hydroxidesolution with 35-55 wt % of one or hydroxide compounds as the maincomponent, e.g., at least 80 wt % and preferably at least 90 wt %, ofthe new treatment composition, together with a small amount, e.g., 0.1-3wt % of an organic acid such as fulvic acid or humic acid, 0.5-4 wt %, achelating agent such as EDTA, 0.01-0.1% volume of a surfactant such assodium lauryl sulphate. This modified treatment composition may becombined with an amount of aqueous ammonium hydroxide solution 25-35 wt% at a ratio of 1:1 to 20:1, again noting that the treated natural gascannot contain more than 14 ppm ammonia. The combined amount (volume) ofthe treatment composition and ammonium hydroxide used in the remediationprocess will be approximately the same as the amount of modifiedtreatment composition discussed above for treating a mixed fluid ofcrude oil and natural gas, e.g., for a well having an output of5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ ofnatural gas/day (24 hours) and wherein the H₂S content of the mixedfluid at 40,000 ppm or higher, the inventors have found that anappropriate amount of treatment composition is in a range of 5 to 20gallons of treatment composition added per hour or 120-480 gallons perday. Alternatively, ammonium hydroxide may be used as one of thehydroxide compounds in the modified treatment composition together withat least one other hydroxide compound, again, wherein the ratio of theat least one other hydroxide compound (collectively) to ammoniumhydroxide may be 1:1 to 20:1, again, with an amount of the modifiedtreatment composition in a range as discussed above. Because aqueoussolutions of ammonium hydroxide generally have concentrations of 25-35wt %, the overall concentration of the hydroxides in such treatmentcomposition may still be in a range of 35-55 wt %, but not asconcentrated as other treatment compositions according to the presentinvention which do not include ammonium hydroxide. Also, ammoniumhydroxide has a much greater vapor pressure than other hydroxidecompounds typically used in the treatment composition, e.g., sodiumhydroxide and potassium hydroxide, which may give the treatmentcomposition more effect on natural gas in the mixed fluid compared to atreatment composition according to the present invention which does notinclude ammonium hydroxide.

The present inventors have discovered that use of the modified treatmentcomposition including or combined with ammonium hydroxide is providedtwo significant effects. First, the overall content of sulfur basedcompounds remaining in the natural gas portion of the treated mixedfluid is reduced compared to use a treatment composition according tothe present invention which does not include ammonium hydroxide. Also,the ammonium hydroxide may cause some sulfur based compounds toprecipitate out of the treated mixed fluid, particularly if a relativelylarge amount of ammonium hydroxide is used, which may not be desirable.Second, the use of the modified treatment composition including orcombined with ammonium hydroxide will generally cause any salt containedin the water vapor contained in the natural gas portion of the mixedfluid to precipitate out. This would be very undesirable for if theprecipitated salt remains in the pipeline and clogs the pipeline, butmay be desirable in some situations, e.g., for use as a pre-treatment ofthe mixed fluid to remove salt before the mixed fluid enters thepipeline.

Intent of Disclosure

Although the following disclosure of exemplary embodiments of theinvention offered for public dissemination is detailed to ensureadequacy and aid in understanding of the invention, this is not intendedto prejudice that purpose of a patent which is to cover each newinventive concept therein no matter how it may later be disguised byvariations in form or additions of further improvements. The claims atthe end hereof are the chief aid toward this purpose, as it is thesethat meet the requirement of pointing out the improvements, combinationsand methods in which the inventive concepts are found.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 is a schematic diagram of a treatment system which may be used inan exemplary embodiment of the present invention.

FIG. 2 is a cross sectional view of a counter-flow reactor according toan exemplary embodiment of the present invention.

FIG. 3 is a flow chart of a natural gas remediation process according toan exemplary embodiment of the present invention.

FIG. 4 is a schematic diagram of a treatment system which may be used ina treatment process for treating a mixed fluid in an exemplaryembodiment of the present invention.

DETAILED DESCRIPTION OF PRESENT EXEMPLARY EMBODIMENTS

Processes for Treating Contaminated Gasses Including Natural Gas from aWell

The present inventor has spent much time investigating possibletreatment compositions and treatment processes for treating natural gas,including natural gas which is highly contaminated, and has discoverednovel treatment compositions, treatment systems and treatment processeswhich are very effective and efficient for treating contaminated naturalgas such that the contaminants therein are quickly remediated down toacceptable levels, even when the natural gas is highly contaminated withhigh levels of H₂S and other contaminants, and whereby the treatmentprocess is practical from an economic point of view, e.g., the cost ofthe treatment process together with the cost of extracting the naturalgas from the earth is far less than the market value of the remediatednatural gas.

Referring to FIGS. 1-3, there are respectively shown a system 100 forremediating contaminated natural gas according to an exemplaryembodiment of the present invention, an enlarged view of a counter-flowreactor 110 in the system 100, and a flowchart of a treatment method orprocess using the system 100 according to an exemplary embodiment of thepresent invention. The system 100 may include a three phase separator102 which receives the fluids output from a well 101 and separates sameinto a gas stream, a aqueous based liquid stream and a hydrocarbon basedliquid stream, a water wash flow cell 104, a chiller 106, a coalescingunit 108, a counter-flow reactor 110 with injectors 120 for injectingtreatment composition, a dehydrator 112 and possibly other and/oradditional components as discussed herein.

The three phase separator 102 is a component that is conventionally usedto separate the three main types of fluids that are extracted from anoil well, i.e., gases and vapors including natural gas, crude oil andso-called “produced water”, all of which contain contaminants, and isconventionally in close proximity to a well for separating the differentcomponents promptly after they are discharged from the well. In one daya typical oil well yields 5 to 30,000 barrels of oil, about 7-8 times asmuch produced water as oil and 1 million to 2 million cubic feet (ft³)of natural gas, and may have a regulator which reduces dischargepressure to about 100 to 300 psi. In the separator flow of the fluids isslowed to give the fluids retention time in the separator whereby thethree fluid will naturally separate from each other based oncharacteristics thereof, with the gasses, vapors and contaminantstherein being discharged at an upper portion of the separator. The restof the components of the system 100 are uniquely combined according tothe exemplary embodiment of the present invention, which may also belocated in close proximity to the well or elsewhere if desired. Throughthe investigations, the inventor has discovered various complicationsrelating to treatment of contaminated natural gas, and has alsodetermined that the most effective and efficient manner of remediatingthe natural gas is to separately remove or remediate different ones ofthe contaminants using respective processes that are effected bydifferent components of the system 100. Collectively, the components ofthe system 100 can be used to achieve a very effective and efficienttreatment process for remediating the contaminated natural gas such thatthe treated gas satisfies all governmental regulations for levels ofcontaminants, even to the point that the remediated natural gas may bedirectly used for heating and the like or condensed into LPG withoutfurther processing.

As part of the investigations the inventor attempted to remediatenatural gas containing high levels of H₂S, e.g., 20,000 ppm and above,as well as various levels of some other sulfur based contaminants, CO₂,N₂. H₂O, and NaCl using the previously proposed treatment compositionsas discussed in PCT/US2018/050913 and PCT/US2018/064015 by placing thecompositions in an elongate, bubble tower type reactor and bubbling orflowing the contaminated natural gas up through the treatmentcompositions, and discovered several complications relating to same.While the previously proposed treatment compositions were initially veryeffective for remediating the H₂S and other contaminants in the naturalgas down to acceptable levels below 5 ppm, the treatment compositionsand such treatment process tend to become much less effective in arelatively short time, such as 4-12 hours of use, due to severalcomplications. Although the effectiveness of the system could begenerally maintained by replacing the treatment composition and cleaningout the system regularly, e.g., every few hours, this is not practicalas it would greatly increase the cost of the treatment process in termsof the amount of treatment composition required, as well as greatlyreduced productivity in the amount of natural gas that may be treated bythe system per unit of time and costs associated with repeatedlystopping and re-starting the flow of natural gas and other fluids from awell. In fact, the complications discovered by the inventor tend toreflect why all conventional treatment processes for remediating highlycontaminated natural gas that existed prior to the present invention areunacceptable as a practical matter, and whereby there are many existingwells around the world that are now just remaining in an unused-shut instate because the cost of the conventional treatment processes does notjustify doing anything to remediate the highly contaminated natural gasfrom such wells. Previously, some nations and states permitted highlycontaminated natural gas to be simply burned/flared as a least expensivemeans of obtaining crude oil that is extracted from the wells with thenatural gas, but due to environmental concerns many states and nationsno longer permit this.

Regarding the complications which the inventor has discovered relatingto the remediation of natural gas, a main complication is that some ofthe contaminants often found in the natural gas, such as salts andcarbonates, may generate significant amounts of precipitates that arereleased from the natural gas as it is being treated and clog upcomponents of the treatment system. Natural gas extracted from wellsaround the world may contain little or no water and no associated saltthat would be dissolved in the water, which wells are referred to as drywells, and such gas may not require additional processing steps toremove these contaminants. However, many wells will contain some amountof water, e.g., 0.001 to 8.0% volume, and any such water will typicallybe saturated with Na and Cl ions from salt such as NaCl because salt isprevalent in the earth where oil and natural gas are extracted, andsalts are highly soluble in water, and whereby the natural gas maycontain 1-15% weight of NaCl. The inventor has discovered that whennatural gas having water with Na and Cl ions therein is remediated in aconventional treatment system, e.g., by passing the gas through a bubbletower filled or partly filed with the treatment compositions, these ionscombine as sodium chloride NaCl which tends to precipitate out of thenatural gas as it is being treated and may quickly build up to asignificant amount in 1-6 hours. Such precipitates can greatly disruptthe treatment system process by plugging up flow lines and the like, andwould have to be removed on a regular basis, again, making the treatmentprocess more complicated and inefficient. The inventor furtherdiscovered that such precipitation of sodium chloride occurs even if thetreatment process uses a treatment solution according to the inventor'sproposal in PCT/US2018/064015, which includes an organic acid such asfulvic acid or humic acid, that helps to prevent formation ofprecipitates in treated liquids/fluids. Another complication which theinventor discovered is that some of the contaminants typically presentin the natural gas interfere with remediation of the H₂S and othertargeted contaminants in various manners, which undesirably inhibit andslow down the remediation process and which may require excess treatmentcomposition to be used and/or to a longer contact time between thenatural gas and the treatment composition in order to remediate thecontaminants down to acceptable levels. Still other complicationsinclude the gaseous nature of the natural gas which is to be treatedwith a liquid treatment composition, and the high pressure, flowrate andvolume at which natural gas is discharged from a well. For thecontaminants that are to be remediated there must be sufficient contactbetween the contaminants in the gas and the hydroxides and otherreactants in the treatment composition, but this is very difficult orimpossible to achieve if the natural gas is flowing at high flow rate orvelocity of ≥10 feet/second when they contact the treatment compositionliquid.

Again, one of the inventors has extensively studied the treatment ofcontaminated gasses in light of the discovered complications, and theinventor has further discovered the novel treatment system, noveltreatment process and novel treatment composition according to exemplaryembodiments of the present invention that address and overcome each ofthe discussed complications, and provide a very effective, efficient andpractical solution for remediating contaminated natural gas and othercontaminated gasses, involving the treatment system 100 and thetreatment process of the exemplary embodiment of the invention as shownin FIGS. 1-3.

The inventor has determined that the first complication pertaining toformation and release of precipitates may be overcome by initiallytreating the contaminated gas to remove the contaminants most likely togenerate precipitates, including Na and Cl ions from salt and carbonateions. With reference to FIG. 1, this may be done, for example, bypassing the contaminated natural gas from the three phase separator 102through the water wash flow cell 104 to remove such ions which arehighly soluble in water. The water wash flow cell 104 may include anelongate chamber having an amount of clean or potable water therein. Forassuring a sufficient contact time between the water and the natural gasas it passes through the water wash flow cell, the flow rate or velocityof the gas may be controlled down to an appropriate level of less than10 feet/sec., preferably ≤5 feet/sec. Additionally, some non-reactivemeans for breaking up the flow of the natural gas into small bubbles orthe like, e.g., bubbles having an average size ranging from about 1-50milliliters, may be provided within the chamber of the flow cell forincreasing the contact area between the gas and the water as it passesthrough the chamber, e.g., perforated baffles, pea gravel or the like,stainless steel wool media, etc. The inventor has performed testing ofthe effects of a water wash on contaminated natural gas obtained from awell, after the natural gas is initially separated from the crude oiland contaminated water in the separator 102, and have found that afterpassing though the water wash flow cell at an appropriate velocity andwith means for breaking up the flow of the natural gas into smallbubbles or the like the contaminated gas contained an undetectableamount of Na and less than 0.03 ppm of Cl. Generally, the salt contentof the water in the water wash flow cell 104 may be monitored to assurethat it is below a predetermined threshold, and the water may bereplaced as necessary when the amount of salt ions and other ions in thewater, extracted from the natural gas, becomes too high. Alternatively,some portion of the wash water may be replaced on an ongoing basis toprevent the salt content thereof from becoming too high.

Removal of the contaminants most likely to generate precipitates,including Na, Cl and CO₃ ions, not only prevents formation ofprecipitates, but the inventor has also discovered that it alsosynergistically improves the efficiency of the treatment compositionthat remediates H₂S and CO₂ according to an embodiment of the presentinvention as discussed further herein.

The inventor has determined that the second complication pertaining tointerference to remediation of primary targeted contaminants includingH₂S by other contaminants in the gas may largely be overcome by alsoremoving most of the water (H₂O) in the natural gas before the treatmentfor remediation of H₂S and other targeted contaminants with thetreatment composition according to the exemplary embodiment.Contaminated natural gas directly from some wells may contain traceamounts of water up to about 5% volume, and after passing through thewater wash flow cell 104 the natural gas will typically contain at least2% volume of water. In the natural gas industry gas containing less than0.5 ppm water is considered as dry gas, while gas having any watercontent of 0.5 ppm or above is considered wet. It is possible to removewater from the wet natural gas using a variety of conventional means,e.g., a glycol tower, a coalescing or dehydrating unit which causeswater vapor in the gas to liquefy and drop out, a candescent absorbentwhich absorbs the moisture from the natural gas, etc. One or more of theconventional means may be appropriate for use according to the exemplaryembodiments of the present invention, e.g., the embodiment of theinvention shown in FIG. 1 includes a chiller 106 and a coalescing ordehydrating unit 108, although use of the coalescing or dehydrating unit108 may be sufficient without the chiller 106. The inventor hasdetermined that for present embodiment of the treatment system andprocess it is important to reduce the water content to a very low level,e.g., less 1 ppm, preferably less than 0.5 ppm in the natural gas inorder to avoid the undesired complications. Even low levels of water.e.g., 1-2 ppm, in the natural gas can add up to significant quantitiesover a period of 24 hours (one day) in the treatment of natural gasflowing from a well. e.g., for an average size well discharging about2,000,000 ft³ of natural gas/day, if the natural gas contains 2 ppm ofwater, this amounts to more than 7 barrels of water/day in the naturalgas. In contrast, an amount of treatment solution according to theexemplary embodiment of the present invention needed to properlyremediate H₂S and other targeted contaminants in 2,000,000 ft³ ofnatural gas down to government regulated levels or lower may be lessthan one barrel, as discussed further herein. Hence, 1-2 ppm of water inthe natural gas will, among other things, significantly dilute thetreatment composition, and this undesirably makes the treatment processless efficient and less effective at remediating the contaminants byincreasing necessary reaction times, causing the reactive components inthe treatment composition to become prematurely spent, reducing pKaprotonic strength of the treatment composition, etc.

Additionally, the inventor has also discovered that because water is oneof the by-products resulting from remediation of H₂S and other targetedcontaminants using the treatment compositions according to the exemplaryembodiments of the present invention, it is also very beneficial toremove water from treatment compositions throughout the treatmentprocess in order to achieve optimum treatment efficiency. The water canbe removed from the treatment composition periodically, e.g., when theamount of water in the treatment composition reaches a predeterminedlevel, or continuously, e.g., with a closed loop arrangement ofwithdrawing, dehydrating and returning some amount of the treatmentcomposition from the reactor 110 at a controlled flow rate. For example,an amount of the treatment composition in the counter-flow reactor 110,e.g., 1-20% volume, may be withdrawn and subjected to a dehydrationprocess in a dehydrator 112 or other appropriate device which removesthe water, and then returned into the counter-flow reactor 110 throughinjectors 120. A dehydrator is basically a steam boiler in which aliquid volume is held in a heating chamber of the boiler with acontrolled heat source to heat the chamber to a desired temperature,e.g., in the treatment process according to the exemplary embodiment ofthe present invention 240° F. to 400° F. would be appropriate, where theliquid treatment composition is heated to the point that the water andsome other contaminants which have been taken up by the treatmentcomposition, including CO₂, sulfides, etc. are vaporized or otherwisedissociated from the composition and vented off, but the treatmentcomposition itself is not adversely affected because it has a muchhigher boiling point than 240° F. to 400° F. By such dehydration processthe treatment composition is effectively regenerated back to a degassedacid base, similar to its original reactive condition. The presentinventor has tested the pKa of some of the treatment compositionaccording to the exemplary embodiment of the present invention which hasbeen regenerated via a dehydration process such as discussed above, andsuch testing shows that the acid base chemical had lost only 2/100ths ofa point in pH concentration in comparison to its original value.

The inventor has determined that the third complication, pertaining tothe nature of the natural gas which is to be treated with a liquidtreatment composition and the high flow rate or velocity at whichnatural gas is extracted from a well, may largely be overcome by:appropriately controlling the flow rate or velocity of the natural gasas it passes through the counter-flow reactor 110, though appropriateregulation of the pressure of the natural gas and appropriate sizing ofthe ID of the reactor to achieve a flow rate or velocity of the naturalgas through the counter-flow reactor 110 of less than 10 feet/sec.,preferably ≤5 feet/sec.; and disrupting the flow of the natural gasthrough the reactor so that the gas cannot flow uninterruptedtherethrough in a stream or as large bubbles, and will instead be in theform of small or very small bubbles, e.g., average size ranging fromabout 1-50 milliliters, having much more surface area for reacting withthe treatment composition. At flow rates above 10 feet/sec. the flowinggas will pass through the liquid treatment composition by largelyforcing the liquid out of the gas' flowpath, and while makinginsufficient contact with the treatment composition to achieve thedesired remediation of H₂S and other targeted contaminants.Additionally, at flow rates above 10 feet/sec. some of the contaminantsin the natural gas may precipitate out of the natural gas, which wouldcause undesirable complications such as discussed above in relation toNa and Cl ions. A gas flowrate of less than 10 feet/sec., preferably ≤5feet/sec. is typically appropriate for assuring sufficient contactbetween the gas and the treatment composition as it passes through thecounter-flow reactor 110. Disruption of the gas flow as it passesthrough the reactor 110 may be accomplished by various means such aspacking the reactor or portions thereof with a non-reactive media suchas indicated at 118 in FIGS. 1-2, e.g., stainless steel wool, pea gravelor the like, perforated plates, etc., through which the natural gas mustpass as it flows through the reactor(s). For example, if the reactor 110provides contact between the treatment composition, as disposed with thenon-reactive media 118 in the reactor, and the natural gas through alength of 12 feet and a flowrate or velocity of the natural gas as itpasses through the reactor is about 5 feet/sec., the gas will take about2.4 seconds to pass through the media as saturated with the treatmentcomposition. Through testing, the present inventor has determined that acontact time of at least 1.5 seconds between the natural gas and thetreatment composition, as disposed with the non-reactive media 118,according to the exemplary embodiment of the present invention should besufficient to assure that the H₂S and other targeted contaminants areremediated down to less than 0.25 ppm in the natural gas in theexemplary treatment system of the present invention, even for naturalgas having very high concentrations of H₂S of 100,000 and more, providedthat the flow rate of gas as it passes through the counter-flow reactor110 is 5 feet/sec. or less and a flow disrupting means is provided inthe reactor. Additional contact time beyond 1.5 seconds will remediatethe contaminants even further. Hence, 2.4 seconds of contact time in thediscussed example should be appropriate for assuring sufficient contacttime to achieve remediation of the contaminants to levels below thegovernment requirements.

Additionally, the inventor has determined that for optimum efficiency,it is desirable that the reactor should not be filled to any extent witha standing column of the treatment composition only, excluding thetreatment composition as disposed with the non-reactive media 118,because this tends to cause the treatment composition to be much lessefficient for remediating the targeted contaminants, e.g., the gas tendsto pass through the column of treatment composition in larger sizebubbles and to take excess amounts of the composition with the gas as itexits the reactor. Although a conventional bubble tower type reactorhaving a column of liquid treatment composition therein and throughwhich the natural gas simply flows may be effective for remediatingnatural gas using the treatment process and treatment compositionaccording to the exemplary embodiment of the present invention, it wouldnot be the most efficient. The inventor has determined that forachieving greater efficiency, it is much better to use a counter-flowtype reactor 110 with the non-reactive media 118 in the treatment systemand process according to the exemplary embodiment of the invention.

Referring to FIG. 2, a counter-flow reactor 110 of the presentembodiment may be an elongate reactor extending vertically having aninlet 114 at a bottom portion thereof where the natural gas isintroduced into the reactor, an upper exit 116 from which the treatednatural gas is discharged from the reactor, non-reactive media 118 whichis provided in one or more sections of the reaction chamber within thereactor as flow disrupting means and through which the gas must pass asit flows through the reactor, various injectors 120 which inject atreatment composition according to the invention embodiment into thereactor such that the composition wets and saturates the non-reactivemedia 118 throughout a treatment process according to the inventionembodiment, a baffle 122 provided near the upper exit 116 which thenatural gas must contact before it reaches the exit, and a lowerdischarge 124 from which treatment composition that accumulates in thebottom portion of the reactor may be withdrawn for dehydration andreuse.

The section(s) of non-reactive media 118 may be provided at intermediateportion(s) of the reactor 110, with an open space 126 at a bottomsection of the reactor below the media, an open space 124 above themedia, and open spaces(s) between sections of the media as shown, andmay be collectively be at least six feet long in the vertical directionto assure sufficient contact time between the natural gas and thetreatment composition in the reactor. If additional contact time isdesired. e.g., for assuring more complete remediation of contaminants,the length of the reactor 110 and/or the section(s) of the non-reactivemedia 118 may be increased, and/or a gas flow rate or velocity of thegas through the reactor may be reduced by appropriately regulating thepressure of the natural gas and/or adjusting the ID of the reactor 110.While it would be ideal if none of the treatment composition accumulatesas a pool in the reactor. e.g., by very carefully controlling the amountof treatment composition injected into the reactor so that it only wetsand saturates the non-reactive media without having any excesscomposition dripping from the media, as a practical matter such controlwould be difficult and expensive to achieve, so that there willtypically be some accumulation of the composition in the open space 124in order to assure that sufficient contact is made between the naturalgas and the treatment composition with the non-reactive media 118.Hence, the open space 126 may have a sufficiently long verticaldimension and/or the accumulated composition may be withdrawn at anappropriate rate so as to prevent any accumulated pool of compositionfrom contacting a lower surface of the non-reactive media 118. The openspace 124 and baffle 122 at the upper section of the reactor permit someor most of any treatment composition retained by the treated natural gasto be separated from the gas and drop back into the reactor before thegas is discharged through exit 116, and the vertical length of the openspace and/or the number and types of baffles may be selected to achievethis purpose accordingly.

The injector 120 for injecting treatment composition into the reactor110 may be provided in any desired number and arrangement, but with theobjective of injecting the treatment composition into the reactor suchthat the non-reactive media may be continuously wetted and saturatedwith the composition throughout the treatment process so that the gaswill have continuous contact with the composition as it passes throughthe non-reactive media 118, but without over-saturating the media withthe composition to any greatly excessive extent, e.g., such that theamount of excess treatment composition dripping from the media 118 iskept to a minimum. Thus, for example, multiple injectors 120 may beprovided at different vertical levels of the reactor and in spacedrelation around the reactor so as to inject the composition onto and/orinto the media 118 in each section thereof, and/or one or more injectors120 may be provided in an upper portion of the reactor which inject orspray treatment composition down onto the non-reactive media, andgravity will force the treatment composition will flow down through themedia. The injectors 120 may inject the composition as very finedroplets and may include some type of atomizing nozzle for such purpose.

The pressure of the gas entering the reactor 110 may be regulated and/orthe ID of the reactor adjusted so that the gas flows upward through thereaction chamber at a rate of 10 feet/sec. or less, and preferably 5feet/sec. or less, while the treatment composition as introduced atintermediate and/or upper portions of the reactor through the injectors120 flows downward based on gravity at about 0.987 feet/sec., thusestablishing a counter-flow of the gas and the treatment composition inthe reactor. In terms of the rate at which the liquid treatmentcomposition is introduced into the counter-flow reactor 110, thislargely depends on the amount of natural gas being treated in thereactor over a given time period, corresponding to the flowrate orvelocity, pressure and density of the natural gas as it passes throughthe reactor, as well as the types and amounts of contaminants in thenatural gas. Again, enough of the treatment composition should beintroduced into the reactor that it fully wets and saturates thenon-reactive media 118, but without greatly over saturating the media.In an ideal setting, an optimum amount of treatment composition will beused to fully the remediate contaminants in the natural gas, and theremediated contaminants will remain in the treated natural gas as itexits the reactor, as well as the spent treatment composition, so thatnothing accumulates in the reactor. Again, in real life things rarelywork ideally, so that the media 118 will likely be over-saturated tosome extent, some amount of the treatment composition will accumulate inthe bottom portion of the reactor, and some small liquid droplets of thetreatment composition which is still reactive will remain in the treatednatural gas along with the remediated contaminants as the natural gasexits the reactor. The amount of treatment composition remaining in thenatural gas as it exits the reactor may be minimized by providing thebaffle 122 in close proximity to the reactor exit so that the naturalgas will contact the baffle 122 before exiting the reactor, and suchcontact may separate some or most of the treatment composition from thenatural gas and permit same to drip back down into the reactor. Theamount of treatment composition which descends into and accumulates atthe bottom portion of the reactor may be used as the source forwithdrawing some of the treatment composition at discharge 128 so thatit may be dehydrated and then re-circulated back into the reactor asdiscussed above.

Based on a substantial amount of experimentation, the present inventorhas discovered a new treatment composition that works exceptionally wellfor remediating H₂S and other targeted contaminants typically containedin natural gas extracted from the earth, including many other species ofsulfides, disulfides, thiols, mercaptans such as ethyl mercaptan, CO₂,N₂, etc. The new treatment composition may also be used to treat othercontaminated gasses besides natural gas. An exemplary embodiment of thenew treatment composition according to the present invention includessome components that are also in the previously proposed treatmentcomposition disclosed in PCT/US2018/064015 for treating contaminatedliquids such as crude oil and so-called produced water that is extractedwith crude oil, and these components perform similar functions when usedas components of the treatment composition for treating contaminatedgasses including natural gas. For example, a concentrated aqueoushydroxide solution may also be used as the main component of theexemplary embodiment of the treatment composition according to thepresent invention, e.g., at least 80 wt % and preferably at least 90 wt%, of the new treatment composition, with the aqueous hydroxide solutioncontaining collectively 35-55 wt %, and preferably 45-55 wt %, of one ormore hydroxide compounds. The aqueous hydroxide solution is veryeffective for reacting with and remediating H₂S and other targetedcontaminants in the contaminated gasses. As another example, a smalleramount, e.g., 0.1-3 wt % of an organic acid such as fulvic acid or humicacid may be provided as part of the exemplary embodiment of the newtreatment composition. As in the treatment composition ofPCT/US2018/064015, such organic acids function to prevent anyprecipitates from being generated and released from the treated gasses.The inventor does not know exactly how such organic acids preventformation of precipitates, but based on the research he has done hebelieves that these organic acids effectively encapsulate or combinewith the remediated sulfur based compounds and other contaminants whichare dissolved in the treated gasses and prevent these from changingphase to a solid or crystal form which would precipitate out of thetreated natural gas, even as the pH of the treated gas is changed. Asstill another example, a small amount of MEA. e.g., 0.1-3 wt %, may beincluded in the treatment composition as an anti-scaling agent similarlyto the treatment composition of PCT/US2018/064015. In addition tocomponents of the composition of PCT/US2018/064015, the new treatmentcomposition according to an exemplary embodiment of the presentinvention may also include some other ingredients, including a smallamount, e.g., 0.5-6 wt %, of ethylenediaminetetraacetic acid or EDTA(C₁₀H₁₆N₈) which is a type of chelating agent that, among other things,helps to improve molar reactivity of the hydroxide compound(s) and helpsto prevent formation of precipitates, and smaller amounts. e.g.,0.01-0.1% volume, of a surfactant such as sodium lauryl sulphate and abuffering agent such as potassium carbonate, etc. Of course, higherproportions of the organic acids, MEA, chelating agent, surfactant andbuffering agent may be used in the treatment composition if desired, butthe inventor has determined that any additional advantageous effect thatmay be achieved by increasing the proportions may not justify theadditional cost.

Relative to the hydroxide compound(s) used in the treatment composition,it is preferable to use only hydroxide compound(s) which do not containelement(s)/component(s) that are also included as a significantcontaminant in the gas being treated. For example, if the gas contains asignificant amount of sodium chloride as a contaminant, then thehydroxide compound(s) in the treatment solution should be other thansodium hydroxide (NaOH), e.g., potassium hydroxide (KOH), lithiumhydroxide (LiOH), magnesium hydroxide (Mg(OH)₂), and manganese hydroxide(Mn(OH)₂, Mn(OH)₄) would be suitable hydroxides for use in thissituation. Of course, if most of the Na and Cl ions are initiallyremoved from the natural gas in the water wash according to theexemplary embodiment of the treatment process, it would be possible touse sodium hydroxide as a hydroxide compound in the treatmentcomposition, but it would still be desirable to use other hydroxidecompound(s) to avoid possible complications.

An exemplary formulation of the treatment composition according to thepresent invention includes the following components, which may becombined;

1) 1.0 liter of aqueous hydroxide solution containing ≥1 hydroxidecompound, excluding NaOH, at a collective concentration of 35-55 wt %,and preferably at least 45 wt %;

2) 0.1-3 wt % of ≥1 organic acid such as fulvic acid or humic acid/literof aqueous hydroxide solution;

3) 0.5-6 wt % of EDTA/liter of aqueous hydroxide solution;

4) 0.01-0.1 wt % of sodium lauryl sulfate as a surfactant/liter ofaqueous hydroxide solution; and

5) 0.01-0.1 wt % of potassium carbonate a buffering agent/liter ofaqueous hydroxide solution.

Although some prior treatment compositions and treatment systems forremoving H₂S and other sulfur based contaminants in crude oil andnatural gas include use of metals-metal ions for bonding to the bondingthe sulfur based contaminants and generating precipitates that can beremoved from the treated fluids, the treatment compositions according tothe present invention preferably do not include metals-metal ionsbecause it is intended that the remediated sulfur compounds will remainin the treated fluids without forming any precipitates that are removedfrom the treated fluids. Ultimately, if and when the treated fluids aretreated at a refinery, as is typical with many of the treated fluids,the remediated contaminants and any excess-unused treatment compositionmay be removed from the fluids. However, if the treated fluids were tocontain metals-metal ions. e.g., zinc, copper, iron, manganese, etc.,the metals-metal ions may have a very detrimental effect on the refineryprocesses, e.g., they may poison and otherwise damage the catalysts usedin the refinery processes. Hence, it is preferred that no metals-metalions are used in the treatment compositions according to the presentinvention.

Relative to the carbon dioxide (CO₂) in the natural gas, this can beremediated with the hydroxide compound(s) in the treatment compositionaccording to the exemplary embodiment of the invention, andtheoretically this would require an additional amount of the treatmentcomposition to be used in the remediation process. For this reason, theCO₂ could be removed from the natural gas before it is treated with thetreatment composition in the counter-flow reactor 110, e.g., by ascrubbing process. Another possibility would be to add a significantamount of carbonate compound(s) such as potassium carbonate (K₂CO₃)and/or sodium bicarbonate (NaHCO₃) to the treatment composition tosaturate it with carbonate ions, so that the hydroxides in the treatmentcomposition would not react with CO₂ to create more carbonate ions.

However, the inventor further discovered that due to certain aspects ofthe treatment process according to the exemplary embodiment of thepresent invention, the exemplary embodiment of the treatment compositionis synergistically very effective and efficient at remediating the CO₂,as well as the H₂S and other targeted contaminants in the natural gaswithout any additional process or component to specially remediate oraddress the CO₂. Particularly, the inventor has discovered that becausethe Na and Cl ions are initially removed from the natural gas using thewater wash flow cell 104 according to the exemplary embodiment andbecause the treatment composition is highly basic with a pH of 13-14,the pH of the natural gas is increased from a typical initial value ofabout 5.8-6.2 to a pH of at least 7 when it contacts the treatmentcomposition in the reactor 110, and this has a synergistic effect forremediating both the H₂S and CO₂ in the natural gas. Particularly, whenthe pH of the natural gas reaches 7.0 and higher in the absence of Clions, these conditions favor a reaction between some of H₂S and CO₂ inthe contaminated gas which forms, among other things, hydroxide ion(OH.). Of course, hydroxide ion is already the main reactant of thetreatment composition from the aqueous hydroxide solution, and theadditional amount of hydroxide ion generated by the reaction of H₂S andCO₂ then helps to efficiently remediate other remaining H₂S and CO₂ inthe contaminated gas. Hence, while is possible to initially scrub CO₂from the natural gas or modify the treatment composition by addition ofcarbonate compound(s) before the natural gas is remediated using thetreatment composition in the reactor 110, the treatment process usingthe treatment composition according to the exemplary embodiment of thepresent invention can efficiently and advantageously remediate the CO₂content in the natural gas down to 1 ppm or less without such additionalprocess or modification.

With the modified treatment composition according to the exemplaryembodiment of the present invention as used in a treatment processaccording to the above discussed aspects of the present invention,including a water wash flow cell 104 to remove Na, Cl ions, a device forinitially removing water from the natural gas, and a counter-flowreactor 110, the present inventor has successfully remediated the H₂Sand other targeted contaminants in natural gas, including mercaptans,thiophene and other disulfides. H₂O, CO₂, NaCl and nitrogen (N₂) down toless than 1 ppm each in a small scale operation, and without generationof any appreciable amount of precipitates from the treated natural gasin the counter-flow reactor, as confirmed by testing of the treatednatural gas. Moreover, the testing did not otherwise indicate anythingabout the treated natural gas that would make it unacceptable undergovernment regulations or such that it has any characteristic that wouldrender it as less than high quality, sweet grade natural gas. Forexample, the pH of the remediated natural gas is around 7.0 or slightlyabove 7.0, while the remediated contaminants and any remaining treatmentcomposition remaining in the remediated natural gas do not adverselyaffect the quality of the gas.

Generally, a well for extracting crude oil and natural gas from theearth may have an inside diameter (ID) of about 4 inches, while the wellmay be drilled to an average depth of 30,000 to 50,000 feet, at whichdepth temperature may be about 1000° F. and pressure may be 100 to 2500PSI. Some wells have pump jacks and some do not, and for those that donot they will have regulators which reduce the pressure down to about300 PSI at the surface well head. A typical well will yield 1 to 2million ft³ of natural gas/day at 100 PSI and 120° F. If a well produces2 million ft³ of natural gas/day at such pressure and temperature andthe gas is passed through a pipe with a 3 inch ID, the flow rate orvelocity of the gas would be about 68 feet/sec. At such velocity itwould be impossible to remediate the natural gas in a reactor accordingto the present exemplary embodiment because the gas would rapidly passthrough the treatment composition with little contact. However, thecounter-flow reactor 110 may have an ID of any appropriate size, e.g.,1-6 feet ID, and the pressure of the gas may be adjusted or regulated toany desired pressure, including pressures above 100 PSI, at which thegas will have a reduced volume and increased density compared to thevolume and density at or below 100 PSI, such that all of the natural gasextracted from a well could be properly handled by one or more of thereactors 110 which are appropriately structured to receive the gas sothat it passes through the reactor(s) at a velocity of ≤5 feet/sec. Forexample, 2 million ft³ of natural gas at 100 PSI and 120° F. beingdischarged from a well through a pipe with an ID of 3 inches is treatedin a reactor having an ID of 2.0 feet, and gas pressure adjusted to 120PSI with a corresponding reduction in volume, the gas velocity throughthe reactor would be about 5 feet/sec., and if the pressure is increasedto 200 PSI with a corresponding reduction in volume, the gas velocitythrough the reactor would be about 0.9 fee/sec. Generally, the pressureand density of the natural gas do not significantly affect theeffectiveness of the remediation process according to the exemplaryembodiment of the present invention. In other words, the remediationprocess is effective for reducing the contaminant levels down togovernment acceptable levels or lower regardless of the pressure anddensity of the gas, as long as the flow rate or velocity of the gasthrough the reactor 110 is less than 10 feet/sec., preferably ≤5feet/sec.

Based on all testing thus far, it is expected that in a full scaleoperation, e.g., including a counter-flow reactor with a 2 ft ID and 21ft tall, and at least 6 ft of which is packed with non-reactive media, acontinuous flow of natural gas from a well at 2 million ft³/day,including high concentrations of H₂S, e.g., 2,000-300,000 ppm, and othercontaminants may be successfully treated down to less than 1 ppm foreach of the contaminants using 1-4 gallons/hour or 24-96 gallons totalof the treatment composition provided the pressure of the gas ismaintained within a range of 100-200 PSI and velocity of the gas is lessthan 10 feet/sec., preferably ≤5 feet/sec. according to the exemplaryembodiment. The specific formulation and/or amount of treatmentcomposition used may be appropriately adjusted based on specificcharacteristics of the natural gas and operations of the differentcomponents of the treatment system 100 to achieve a desired result. Ofcourse, the counter-flow reactor 110 and other components of theexemplary treatment system 100 in FIGS. 1-2 may be constructed in anysuitable size appropriate for treating any given amount of natural gasbeing output from a well. Similarly, it is also possible to use multiplesystems 100 to handle the natural gas from a given well. Still further,it is possible to use reactor which are disposed horizontally ordiagonally rather than vertically.

Referring to FIG. 3 there is shown a treatment process for remediatingH₂S and other contaminants in natural gas and other gasses according toan exemplary embodiment of the present invention, and it generallycorresponds to the exemplary treatment system 100 of FIG. 1. At step S1a flow of a contaminated gas is received, e.g., a flow of contaminatednatural gas from the separator 102 after it has been separated from thecrude oil and produced water. At step S₂ the pressure and volume of theflow of natural gas is adjusted such that the flow rate or velocity ofthe gas will be less than 10 feet/sec., preferably ≤5 feet/sec, as thetreatment process continues. At step S3 it is determined whether thecontaminated gas contains water and/or chemicals that are likely toprecipitate from the treated gas in amounts such that these contaminantsshould be initially removed, and if YES, the contaminated gas is treatedin the water wash flow cell 104 to remove ions of chemicals such as Na,Cl and CO₃ at step S4 and/or in step S5 is treated remove water down toless than 1 ppm, preferably ≤0.5 ppm, e.g., in the coalescing unit 108and optionally the chiller 106. If the answer at S3 is NO or after thechemicals and water are removed in steps S4, S5, at step S6 the flow ofcontaminated gas is then passed through a reactor such as thecounter-flow reactor 110 where H₂S and other targeted contaminants areremediated using the treatment composition, e.g., the treatmentcomposition is injected via nozzles 120 to saturate the non-reactivemedia 118 so that the gas will flow through the saturated media in theform of very small bubbles, e.g. average size ranging from about 1-50milliliters, for at least 1.5 seconds. At step S7 some portion of thetreatment composition in the reactor is removed, some of the water andpossibly some other contaminants that have combined with the treatmentcomposition are removed, e.g., by processing the treatment compositionin the dehydrator 112, and the dehydrated treatment composition isinjected back into the reactor, along with additional new treatmentcomposition. Finally at step S8, the treated natural gas as dischargedfrom the reactor is sold, burned, transported to a refinery for furtherprocessing, or otherwise processed for transport and/or storage.Additionally, while not shown in FIG. 3, sensors will be provided inassociation with different components of the treatment system andvarious parameters of the treatment process may be monitored to makesure the contaminants are being properly remediated and that the variouscomponents of the system are operating properly, and if necessaryappropriate adjustments may be made to keep the treatment processoperating in an efficient manner.

The treatment process according to the exemplary embodiment mayconducted at various temperatures, including ambient up to 200° F., andmay be conducted at various pressures, but for purposes of efficiencyand given the flow rate, pressure and volume of natural gas from a wellit may be desirable to conduct the treatment process at pressuressignificantly above ambient. e.g., 50-300 PSI, as the volume andvelocity of the natural gas is reduced as pressure goes up, whereas thetreatment system, process and composition according to the exemplaryembodiment of the invention remains very effective at remediating thecontaminants down to very low levels even as the pressure increases. Thetreatment process according to the exemplary embodiment may conducted ina continuous, partly continuous manner or batch manner, although forvery large volumes of gas such as natural gas coming out of a well,batch manner may not be practical. A continuous or partly continuoustreatment processes may involve flowing a continuous stream of the gasthrough the system 100 for any given period of time, e.g., hours, days,weeks, etc., and the longer the treatment process may continuouslyproceed while sufficiently remediating the contaminants in the gas, themore efficient and cost effective the process will be.

Overall, the treatment process according to the exemplary embodiment ofthe present invention is very effective and cost efficient forremediating contaminated gasses, including highly contaminated naturalgas. Again, in a small scale operation the present inventor hasdetermined that H₂S and other targeted contaminants in natural gas,including mercaptans, thiophene and other disulfides, H₂O, CO₂, NaCl andnitrogen (N₂) are remediated down to less than 1 ppm each, and it isexpected that the same excellent results will be achieved in largerscale operations of the invention. In contrast, no conventionaltreatment composition/system/process existing at the time of the presentinvention has proven sufficiently effective and efficient to remediatehighly contaminated natural gas, and has resulted in many existing wellsbeing currently unused and shut in, which is significant given that theaverage cost to put in one such well is several millions of dollars. Infact, the highly contaminated natural gas as remediated using thetreatment composition, treatment system and treatment process accordingto the exemplary embodiment of the present invention is so cleanrelative to all of the contaminants originally therein, that it may bedirectly sold as sweet natural gas without further processing, whichcreates new, advantageous possibilities for efficiently and economicallyhandling the natural gas. For example, the remediated natural gas may bedirectly condensed into liquefied petroleum gas (LPG) in the vicinity ofthe well from which it is extracted, by locating necessary equipment inthe vicinity of the well to process the gas directly after it isdischarged from the treatment system of the invention. As will beappreciated, being able to directly liquefy the natural gas in thevicinity of the well, and without having to first transport same to arefinery or the like for further processing, permits the gas to be veryeconomically stored and transported.

Examples of Treatment Process

The inventor has conducted a study is to determine the behavioraleffects based on temperature and pressure of natural gas containingsignificant amounts of various contaminants that are typically found innatural gas, including Na, Cl, H₂S, CO₂, H2O and carbonates. Thesecontaminates pose many challenges to remediation of same, e.g.,over-dosing, formation and release of precipitates, etc. Also, it isimportant to understand that the natural gas being extracted viadifferent wells, and even the natural gas extracted from a given well atdifferent times, will contain different contaminants and differentlevels of contaminants. Correspondingly, it is desirable andadvantageous that the treatment system, process and compositionaccording to the exemplary embodiment can effectively and efficientlyremediate essentially any natural gas regardless of the types andamounts of contaminants therein.

The study was performed using a natural gas sample obtained from LilisAntelope site in a 500 gallon bulk methane tank at pressure 135 PSI. Thegas was tested and found to contain, among other contaminants, 50,000ppm H₂S, 2% H₂O vapor saturated with Na, Cl ions. A small scale versionof many components of the treatment system 100 was constructed,including: a water wash flow cell 4 inch ID PVC×5 ft long, volume ofwater 3.0 gallons for removing the Na, Cl ions; a bendix air dryer, 5.20ft³/min., self purging for reducing water content down to 0.5 ppm; and acounter-flow reactor 4 inch stainless steel×5 feet long, of which 4 feetare packed with stainless steel wool media. For a first run of the studythe water wash flow cell did not include any non-reactive media forbreaking up the flow of the natural gas, but in subsequent runs of thestudy a section of the reactor was packed with stainless steel wool,non-reactive media. A treatment composition according to the exemplaryformulation above was injected into the counter-flow reactor such thatthe stainless steel wool media would be saturated with same.Additionally, a gas flow regulator with an H₂S monitor was provided tomonitor the H₂S content of the treated natural gas after it leaves thecounter-flow reactor.

The first run of the study was performed at 60 to 65° F. at ambientpressure and a flow rate of 4 ft³/hour for periods of 2 to 3 hours at atime, totaling a combined run of 8 hours total. The H₂S in the gas wasremediated down to 0 ppm or non-detectable for the complete run.However, 6 hours in to the run salts and carbonate solids formedplugging the system supply lines. The primary cause of this problem wasdetermined to be that the water wash became ineffective at the 6 hoursuch that significant amounts of salt and carbonate ions remained in thenatural gas and then precipitated out in other components of the system.

This study was run again in similar manner except the pressure wasincreased to 80 PSI with the same temperature conditions, the flow ratewas increased to 1 ft³/minute for a period of 4 hours and thenon-reactive media was provided in the water wash flow cell. For thisrun it was noted that no significant amounts of precipitates werereleased from the gas and did not plug up any components of the system,and the H₂S in the gas was again remediated down to 0 ppm ornon-detectable for the complete run. Another similar run of the studyused the same temperature and pressure, but increased the flow rate to 5ft³/minute for a period of 4 hours. Again, the water wash remainedeffective for removing salt and carbonate ions from the gas for the timetotal of 8 hours in these two runs of the study. Analytical testing wasdone on the water wash and gas after the runs of the study and theresults were as follows.

After the first 6 hrs run at atmospheric pressure the water in the waterwash flow cell contained 1% sodium and 5.47 ppm chlorides, while thenatural gas discharged from the water wash flow cell contained 3% watervapor. After the two runs at 80 PSI pressure for a total of 8 hrs thewater in the water wash flow cell contained 1% sodium and 7.367 ppmchlorides, while the natural gas discharged from the water wash flowcell contained 3% water vapor. The treated natural gas discharged fromthe counter-flow reactor after the initial run at atmospheric pressurecontained 60 to 85 ppm H₂S compared to the original 50,000 ppm. To bringthe H₂S content down to 0 ppm or non-detectable, five cycles of 20 mleach of additional treatment composition were injected into thecounter-flow reactor to saturate the stainless steel wool media in thereactor. The natural gas as discharged from the counter-flow reactorwould remain at 0 ppm for one hour and 20 minutes after such injectionof additional treatment composition before the H₂S content of thedischarged gas would return to 60 to 85 ppm. Repeating the injectionprocess produced the same result and time frame for the H₂S.

From such study the inventor determined a few things, including that: itis important that the water wash flow cell also be packed withnon-reactive such as stainless steel wool similar to the counter-flowreactor to break any coarse bubbles and increase the contact surfacearea between the gas and the water for maximum performance in thereduction of salt and carbonate ions and reduction of same in anycarryover vapor; it is important that the non-reactive media in thecounter-flow reactor cell maintain saturation with the treatmentcomposition to assure that H₂S content is remediated down to levelsbelow 5 ppm, and preferably close to 0 ppm; and if the Na, Cl ionsremain in the water in the natural gas when the gas is reacted with thetreatment composition in the reactor, this will tend to form some HCl,which in turn makes it necessary to increase the amount of treatmentcomposition and/or the amount of hydroxides in the treatment compositionfor remediating the HCl as well as fully remediating the H₂S in thenatural gas down to acceptable levels.

The inventor performed a further, very simple study to demonstrate theadverse effects of Na, Cl ions and water on treating contaminatednatural gas using the treatment composition according to the exemplaryembodiment of the invention. In this study a 1 liter Tedlar® bag wastaken of the untreated, wet gas bulk tank from the Lilis Antelope sitediscussed above and a 1 liter Tedlar® bag of the natural gas after ithas passed through the water wash flow cell and the bendix air dryer forremoving water vapor and Na, Cl ions. Both bags were injected with 0.1micro liters of the treatment composition, and then the bags were shakenfor 3 minutes and tested for H₂S. The wet gas from the bulk tank stillhad 50,000 ppm H₂S, a pH of 5.8 and the original amount of Na, Cl ions.In contrast, the dry gas had 30 ppm H₂S down from 50,000 ppm, a pH of10, 0.0 ppm Na and 0.026 ppm Cl.

The results of the above examples are very advantageous, not only interms of effectively and efficiently remediating the many contaminantscontained in the natural gas, but also in that the treatment process maybe run continuously for an extended period, which makes the treatmentsystem and treatment process practical for efficiently remediating H₂Sand other contaminants in gasses, even highly contaminated gasses, atreasonable cost.

The foregoing description is given for clearness of understanding only,and no unnecessary limitations should be understood therefrom, asmodifications within the scope of the invention may be apparent to thosehaving ordinary skill in the art and are encompassed by the claimsappended hereto. For example, while the exemplary embodiment of thetreatment system 100 and treatment process according to the inventioninclude separate components 104, 106, 108, 112 in which sub-processesare conducted for removing salt and water from the contaminated naturalgas, as well as the counter-flow reactor 110 in which the treatmentcomposition is used to mitigate H₂S and other targeted contaminants, itis conceivable that the dehydrator 112 or coalescing unit 108 used forremoving water from the treatment composition may also be used as areactor in which the treatment composition is used to mitigate H₂S andother targeted contaminants, such that the treatment composition andnatural gas would be reacted together in the dehydrator or coalescingunit at the same time as the dehydration process. The modification wouldbe add the influent natural gas piping to the dehydrator or coalescingunit so that the natural gas is remediated with the treatmentcomposition simultaneously with water being removed from the treatmentcomposition. This is somewhat similar to how a triethyleneglycol (TEG)regeneration system works. The difference between glycol and theproposed modification to the present system and process is that glycolonly displaces water, but does not treat CO₂, H₂S or any other gasses.The treatment composition according to the exemplary embodiment of theinvention treats all the contaminated gasses in one pass and done in thedehydrator would eliminate the need for the reactor towers, maintenance,and corrosion problems. As another example, it is possible to vary theparticular formulation of the treatment composition by increasing ordecreasing the specific amounts of the various components, by excludingone or more of the components, and by including other components in thetreatment composition of the exemplary embodiment, such as carbonates toreduce reactivity of the hydroxide compound(s) with CO₂, anantibacterial such as a sulfite compound, etc.

Modifications to the Treatment Process

As discussed herein one important aspect of the treatment process forremediating a contaminated gas, such as natural gas from a well, is theflowrate of the gas as it passes through a quantity of treatmentsolution as contained in a reaction chamber or the like, e.g., the flowrate should be less than 10 ft/sec and preferably ≤5 feet/sec., and thedesired flowrate may be achieved by appropriately adjusting the size ofthe reaction chamber through which a given volume of the gas flows/unittime and/or appropriately adjusting the pressure of the gas. In thisregard, the present inventors have discovered an unusual and unexpectedadditional benefit that may be achieved when the pressure of the gas isincreased or adjusted using a compressor as part of the treatmentprocess.

The inventors have discovered that when a compressor is used to increasethe pressure of contaminated gas after the gas has passed through awater wash flow cell of potable water to remove ions of salt moleculesand the like, and before the gas is further processed to remove waterand to be remediated in a reactor using a treatment compositionaccording to the present invention, it is possible to achievesignificant remediation of the H₂S and CO₂ contaminants by introducingan amount of the treatment composition according to the present 5linvention into the gas before and/or after it is compressed by thecompressor. For example, in an actual treatment process according to thepresent invention involving treatment of contaminated natural gas from awell at a rate of 1,000,000 ft³/day, wherein the gas contained 80,000ppm of H₂S and 160,000 ppm of CO₂, an amount of a treatment compositionaccording to the present invention was added to the water used in thewater wash flow cell prior to passing the gas through the water washflow cell in order to increase the pH of the water to be within a rangeof 13-14. The particular treatment composition used included 93 parts byvolume of an aqueous hydroxide solution containing KOH at approximately45 wt %, 3 parts by volume of an aqueous solution of fulvic acid atapproximately 5 wt %, 4 parts by volume of an aqueous solution of EDTAat approximately 40 wt % and less than 1 part by volume of a surfactant.The amount of treatment composition added to the wash water was muchless than the amount of treatment composition which would be used in thecounter flow reactor for specifically remediating the H₂S and CO₂contaminants in the natural gas and it is otherwise significantlydiluted by the wash water, but would nonetheless have some positiveeffect in remediating some amount of the H₂S and CO₂ contaminants as thenatural gas passed through the water wash. However, the inventors werevery surprised to discover that by adding the compressor as part of thetreatment system after the water wash flow cell for increasing thepressure of the natural gas at this stage in the treatment process, theactions of compressing the natural gas to increase its pressure by 50 to100 psi up to a total of 170-220 psi, the content of H₂S in the naturalgas was reduced by approximately 20,000 ppm to around 60,000 and thecontent of CO₂ in the natural gas was reduced by approximately 40,000ppm to around 120,000 ppm.

The type of compressor used in the experiment was a reciprocating pistontype compressor, but for purposes of the invention any type of gascompressor may be used, including a piston compressor, a leadscrewcompressor, a rotary vein compressor or any other type compressor willwork. Although the inventors do not yet fully understand why or how theactions of the compressor achieved this significant reduction in H₂S andCO₂ contaminants, it is believed to involve the relatively small amountof treatment composition picked up by the natural gas as it passedthrough the water wash flow cell reacting with these contaminants basedon the compression and expansion of the gas as it is compressed by thecompressor to the higher pressure and then expanded to some extent as itis released from the compressor back into the system piping leading fromthe compressor to other components of the system.

Based on this unexpected result, the inventors further experimented byintroducing additional amounts of the treatment composition according tothe present invention in an atomized form into the natural gasimmediately before it is received by the compressor and immediatelyafter it is discharged by the compressor. The additional amounts of thetreatment composition introduced into the natural gas in theseexperiments was approximately 1.4 gallons/hour for the gas which wasflowing at a rate of 1,000,000 ft³/day. The additional amount of thetreatment composition added into the natural gas immediately before itwas received by the compressor resulted in a further small reduction ofthe H₂S and CO₂ contaminants, but not enough to justify the additionalcost of the added step of introducing the additional treatmentcomposition into the natural gas. On the other hand, the additionalamount of the treatment composition added into the natural gasimmediately after it was discharged by the compressor very surprisinglyresulted in a complete reduction of the H₂S and CO₂ contaminants down toapproximately 0 ppm. Due to such surprising result, it was not necessaryto further treat the natural gas in the remaining components of thetreatment system according to the present invention as there was nofurther H₂S and CO₂ to remediate, although if desired the gas could befurther treated for removing other contaminants, including water and anysalt ions not removed in the water wash. As with the normal treatmentprocess using the treatment composition according to the presentinvention whereby H₂S and CO₂ are remediated by reacting with thetreatment composition, such reactions are advantageously non-reversibleso that the sulfur compositions remaining in the remediated natural gasdo not revert to H₂S to any appreciable extent.

Again, the inventors do not fully understand why this added stepinvolving the compressor and introduction of an amount of the treatmentcomposition into the natural gas immediately after it is discharged bythe compressor is so effective at remediating H₂S and CO₂. However, theinventors' theory is that the compressor compresses the gas creating adenser gas with the molecules closer together at a higher pressure incomparison to the pressure in the system piping into which the gas flowswhen the gas is discharged from a discharge port of the compressor. Atthe compressor discharge port the pressure of the gas is reducedsomewhat to correspond to the to the gas pressure in the piping, andwith such pressure reduction the volume of the gas is expanded somewhat.This expansion of the gas is believed to allow the atomized treatmentcomposition to be absorbed into the gas creating a greater concentrationof the treatment composition and thereby creating a greater reaction inthe remediation of H₂S and CO₂ to zero ppm. Additionally, a secondpossible factor is that the temperature of the discharged compressed gasis increased from ambient temp increased to 180° F. to 200° F. degreesthrough the compressor and being discharged into the atomized treatmentcomposition. As the gas is compressed it builds heat expanding thesurface area of the H₂S and CO₂ molecules, and as the molecules arecovered with the atomized treatment composition they begin to cool. Thistemperature reduction reduces the surface area of the molecules leavinga high concentration of the alkaline treatment composition, which isbelieved to cause the complete remediation of H₂S and CO₂ in the gas.

Alternative Treatment Compositions and Treatment Processes Using Same

As discussed herein, one of the significant complications involved inremediating H₂S and CO₂ in contaminated gases such as natural gaspertains to formation and release of precipitates such as salts from thetreated gases because the precipitates may readily clog up the treatmentsystem and make it inefficient and impractical, and that one solution tosuch complication as provided by the present invention is to initiallytreat the contaminated gas to remove the contaminants most likely togenerate precipitates, including Na and Cl ions, using a water wash flowcell or the like. According to the present invention, another possiblesolution to this significant complication is to provide a treatmentcomposition which selectively targets specific contaminants forremediation including H₂S and CO₂ but which does not significantly reactwith other contaminants such as Na and Cl ions and does not cause theseother contaminants to form precipitates which are released from thetreated gases.

Particularly, according to another exemplary embodiment of the presentinvention the aqueous based treatment composition including hydroxidecompound(s), organic acid(s) such as fulvic acid and humic acid, andEDTA is modified by being combined or mixed with a hydrocarbon basedliquid and then the modified treatment composition is used to remediatespecific contaminants including H₂S and CO₂ in a treatment system andprocess according to the present invention. As discussed herein, theaqueous treatment composition according to an embodiment of the presentinvention may be a concentrated aqueous hydroxide solution with 35-55 wt% of one or more hydroxide compounds used as the main component, e.g.,at least 80 wt % and preferably at least 90 wt %, of the new treatmentcomposition, together with 0.1-3 wt % of an organic acid such as fulvicacid or humic acid and 0.1-6 wt % of a chelating agent such as EDTA andoptionally a small amount of a surfactant. A quantity of such treatmentcomposition may be modified by being thoroughly combined or mixed with aquantity of a hydrocarbon based liquid, which may be refined or notrefined and may have an API rating in a range of about 30-50. Forexample, refined hydrocarbon based liquids that may be used includes #1diesel fuel, #2 diesel fuel and off road diesel fuel. The quantities ofthe aqueous based treatment composition and the hydrocarbon based liquidwhich are combined may be substantially equal, but could be modified toinclude more or less of either component, e.g., the total mixture maycontain 40 volume % of the aqueous based composition and 60 volume % ofthe hydrocarbon based liquid, 60 volume % of the aqueous basedcomposition and 40 volume % of the hydrocarbon based liquid, etc.Specific gravity of the aqueous composition may be around 1.4 andspecific gravity of the hydrocarbon based liquid may be around 0.98,such that specific gravity of the blended mixture will be somewhere inbetween these values. The modified treatment composition may be used totreat contaminated gases such as natural gas in a treatment system suchas shown in FIGS. 1-2 and a treatment process such as shown in FIG. 3,e.g., the modified treatment composition is substituted for the normalaqueous based treatment composition in the treatment system of FIGS. 1-2and the treatment process of FIG. 3 as discussed above.

The blended, modified treatment composition is essentially an alkalineoil with a pH of about 14, although the aqueous and hydrocarbon basedportions of the mixture do not form a stable, homogeneous mixture andwill separate from each other if left undisturbed for a length of time.Based on testing conducted, the chemical compounds in the alkalineaqueous portion of the modified treatment composition will mitigate theH₂S and CO₂ in the gas stream similarly to the unmodified treatmentcomposition, so the main challenge was to prevent other contaminantssuch as salt ions from reacting with the chemical compounds to formprecipitates. Although the exact mechanisms involved may not be fullyunderstood, the modified treatment composition is believed to work asfollows in remediating contaminants such as H₂S and CO₂ in thecontaminated gases, but without causing other contaminants in the gassuch as salt ions to generate and release precipitates. First, becausethe pH of the modified treatment composition is about 14, undesiredformation of HCl may be avoided and the hydroxide compound(s) in theaqueous portion of the treatment composition may efficiently remediatethe H₂S and CO₂ similarly to the unmodified treatment composition inthat the H₂S and CO₂ are in gaseous phase and may be directly contactedby and react with the chemical compounds in the modified treatmentcomposition even though the chemical compounds are mixed with thehydrocarbon based liquid. On the other hand, the salt ions that tend tocause precipitates are not in gaseous phase, but are mostly contained inthe water vapor in the natural gas stream being treated due to the highsolubility of these ions in the water. Further, because the hydrocarbonbased portion of the modified treatment composition is not miscible withthe water vapor, this effectively prevents the chemical compounds in themodified composition from reacting with the salt ions in the watervapor, and hence prevents formation of precipitates. In other words, thehydrocarbon based portion of the modified treatment compositioneffectively acts as a buffering agent that prevents the modifiedtreatment composition from reacting with the salt ions to formprecipitates, even though the chemical compound is able to remediate theH₂S and CO₂ in the gas stream. The present inventors have conductedtesting on a contaminated natural gas stream that has been treated usingthe modified treatment composition according to the present inventionand the testing shows that the water vapor and salt ions are still inthe water vapor in the treated gas stream after treatment.

As discussed herein, another concern relating to treatment of naturalgas contaminated with H₂S and CO₂ is that at pH below 7 H⁺ ions from H₂Smay react with the chloride ions from salt in the natural gasundesirably creating hydrochloric acid (HCl), which in turn reacts withthe hydroxide compound(s) to undesirably use up the hydroxidecompound(s) at a faster rate, and which may undesirably lower the pH orraising the PKa of the treatment composition. However, because thenormal aqueous based treatment composition according to the presentinvention has a high pH of around 14, this increases the pH of thenatural gas being treated above 7, at which H⁺ ions do not exist but areinstead converted to H ions, which advantageously do not result in theformation of HCl. This advantageous effect is also achieved using themodified treatment composition according to the present invention inwhich aqueous and hydrocarbon based liquids are mixed together becausethe modified treatment composition also has a pH of about 14.

Systems and Processes for Treating a Contaminated Fluid Mixture ofLiquids and Gasses

Referring to FIG. 4, there is shown a system 200 for remediatingcontaminated mixed fluids according to an exemplary embodiment of thepresent invention. The system 200 may generally include a horizontalreactor 202 which receives an oil and natural gas mixture from a two wayseparator 204, a discharge nozzle 206 which discharges the mixed fluidinto the reactor, a discharge outlet 208 which discharges the fluidmixture from the reactor after treatment composition has been addedthereto, a supply of the treatment composition 210, a re-circulationpump 212 which withdraws a portion of the mixed fluid from the reactor202 via a discharge outlet 214 at a bottom of the reactor, adds sometreatment composition from the supply 210 thereto and then adds thefluid mixture and treatment composition to the flow of untreated fluidmixture from the separator 204 which is flowing into the reactor. Acontroller 216 such as a programmed electronic processing unit (ECU) maybe provided for controlling operations of the system 200.

The horizontal reactor 202 may be formed of an appropriate material suchas carbon steel which is resistant to reacting with the mixed fluid andthe contaminants in the mixed fluid including H₂S, and may have anappropriate size based on the volume of mixed fluid being treated. Forexample if the volume of mixed fluid being treated is 5,000-10,000barrels of crude oil and 10 million to 20 million ft³ of natural gas/day(24 hours), an appropriate size for the reactor 102 may be 5-10 feet indiameter and 12-25 feet long. The reactor may alternatively be arrangeddiagonally.

The discharge nozzle 206 may include one or more pipe(s) extendinglongitudinally along the lower portion of the reactor and havingnumerous small openings formed therein in pipe(s), whereby the fluidmixture will enter the reactor in the form of small fluid streamscontaining bubbles of the gas in the mixture. The pressure of the mixedfluid stream and the gas bubbles will cause fluid streams from thenumerous small openings to flow upward through a large quantity of themixed fluid and treatment composition already in the reactor so as tothoroughly mix with the same. By the time that the mixed fluid andtreatment composition reaches the upper portion of the reactor where aportion of the same is discharged through the outlet 208 the mixed fluidand treatment composition are combined in a fairly homogenous mixture.

The re-circulation pump 212 may be any appropriate type of pump, but theinventors have found that a pneumatic-diaphragm works appropriately fornot only for re-circulating and mixing the mixed fluid with treatmentcomposition from the supply 210, but also for maintaining anappropriate, desired concentration of the treatment composition in thereactor and in the mixed fluid discharged from the reactor throughoutlet 208. A portion of the mixed fluid in the reactor may becontinuously withdrawn from a bottom portion of the reactor, mixed withadditional treatment composition and then again flowed into the reactoralong with additional mixed fluid from the separator. For continuouslyadding the treatment composition to the reactor, the concentration ofthe treatment composition in the mixed fluid being withdrawn from thereactor may be monitored to determine by a sensor (not shown). If therate at which the treatment composition is being added needs to beadjusted based on the sense value, the rate at which the treatmentcomposition is added via the re-circulation pump 212 may beappropriately adjusted by the controller 216.

The present inventors have discovered that when the previously proposedtreatment compositions such as disclosed in PCT/US2018/064015, themodified treatment compositions discussed herein and variations thereofare used for treating a continuously flowing, large volume of a fluidmixture highly contaminated with H₂S and other using the treatmentsystem treatment process as shown in FIG. 4, such fluid mixture may beefficiently and effectively treated for remediation of the H₂S and othercontaminants. After being combined with the treatment composition in thereactor 202 and being discharged from the outlet 208 the fluid mixturecontinues to flow in a pipeline toward another pipeline that will sendthe fluid mixture to a refinery, e.g., typically for many miles and overa period of hours, the treatment composition will react with andremediate the H₂S and other contaminants in both the liquid and gaseouscomponents of such fluid mixture such that the content of thesecontaminants will be reduced to appropriate levels by the time the fluidmixture arrives at the pipeline leading to the refinery, and veryimportantly essentially no precipitates will be discharged from thetreated fluid due in large part to the presence of the organic acid(s)such as fulvic acid and humic acid in the treatment composition.Discharge of any amount of precipitate(s) from the treated fluid is veryundesirable as this may partially or completely clog the pipeline, andwould require the pipeline to be shut down for corrective action. Theinventors have determined that even if the contaminated fluid mixturecontained a relatively high content of H₂S when it was discharged fromthe separator, e.g., 40,000 ppm or higher, the content of the H₂S in theliquid portion of the mixture, e.g., crude oil, may be reduced downbelow 5 ppm and the content of the H₂S in the gaseous portion of themixture, e.g., natural gas, may be reduced down below 20,000 ppm andwithout formation or release of any appreciable amount of precipitate(s)from the treated fluid mixture.

Again, the present inventors have discovered that for such treatmentsystem and process, treatment compositions such as disclosed inPCT/US2018/064015, modified treatment compositions as disclosed herein,as well as variations thereof, are appropriate for treating thecontaminated fluid mixture, such as crude oil, and these componentsperform similar functions when treating the contaminated mixed fluidcontaining crude oil and natural gas. PCT/US2018/064015 discloses aconcentrated aqueous hydroxide solution with 35-55 wt % of one or morehydroxide compounds as the main component, e.g., at least 80 wt % andpreferably at least 90 wt %, of the new treatment composition, togetherwith a small amount, e.g., 0.1-3 wt % of an organic acid such as fulvicacid or humic acid, and possibly a small amount of MEA, e.g., 0.1-3 wt%, and perhaps an antibacterial compound such as potassium silicate. Theconcentrated hydroxide compound(s) react with H₂S to remediate same,while the organic acids such as fulvic acid and humic acid function toprevent any precipitates from being generated and released from thetreated fluid, and MEA functions as an anti-scaling agent. On the otherhand, the modified treatment composition disclosed herein in USSN mayalso be an aqueous solution primarily including a high concentration ofhydroxide compound(s), e.g., 35-55 wt % of one or more hydroxidecompounds as the main component, e.g., at least 80 wt % and preferablyat least 90 wt %, of the treatment composition, 0.1-3 wt % of an organicacid such as fulvic acid or humic acid together with a small amount,e.g., e.g., 0.5-6 wt %, of EDTA (C₁₀H₁₆N₂O₈) which is a type ofchelating agent that, among other things, helps to improve molarreactivity of the hydroxide compound(s) and helps to prevent formationof precipitates, and possibly smaller amounts, e.g., 0.01-0.1% volume,of a surfactant such as sodium lauryl sulphate and a buffering agentsuch as potassium carbonate, etc. The pH of such treatment compositionsaccording to the present invention is approximately 14.

An appropriate amount of such treatment compositions will, of course, bebased on amount of the mixed fluid being treated. For a typical oil wellwith well head piping having a diameter of 2-10 inches and an output of5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ ofnatural gas/day (24 hours) and wherein the H₂S content of the mixedfluid at 40,000 ppm or higher, the inventors have found that anappropriate amount of treatment composition is in a range of 5 to 20gallons of treatment composition added per hour or 120-480 gallons perday. The inventors have determined that under these conditions thetreated crude oil in the mixed fluid will have less than 5 ppm H₂S andoften 0 ppm H₂S, while the treated natural gas in the mixed fluid willhave less than 20,000 ppm H₂S, which is appropriate to make the gassaleable and acceptable for the pipeline to the refinery. Further, itshould be noted that the pipelines through which the mixed crude oil andnatural gas flow often have bacterial growing therein, e.g., which isattached to the walls of the pipeline, and that such bacterial may be aproblem for helping H₂S and other sulfur-based contaminants remain in orbecome regenerated in the mixed fluid. Hence, the amount of treatmentcomposition which is added to mixed crude oil and natural gas accordingto the present invention may initially be at a higher rater within thediscussed range of 5 to 20 gallons of treatment composition added perhour so that the treatment composition may kill the bacteria, and aftera period of time sufficient to kill the bacteria the dosage rate may bereduced to a lower value within the range.

Modifications may be made to the above treatment process and areincluded within the scope of the present invention. For example, whilethe exemplary embodiment of the treatment system 200 includes there-circulation pump 212 which not only withdraws some portion of themixed fluid from the reactor 202 but also adds treatment compositionfrom the supply 210 and then flows these into the fluid stream from theseparator 204, it is certainly possible to separately add the treatmentcomposition to the reactor 202 without use of the pump 212 and for thefluid output of the pump to be separately flowed into the reactor apartfrom the mixed fluid stream from the separator 204.

Use of Ammonium Hydroxide in or with the Treatment Composition

Another modification to the treatment composition which the presentinventors have determined may be used for treating a contaminated mixedfluid of crude oil and natural gas involves use of a concentratedaqueous, ammonium hydroxide (NH₄OH) solution, e.g., 25-35 wt %, togetherwith or as one of the hydroxides in the composition. For example, amodified treatment composition may be a concentrated aqueous hydroxidesolution with 35-55 wt % of one or hydroxide compounds as the maincomponent, e.g., at least 80 wt % and preferably at least 90 wt %, ofthe new treatment composition, together with a small amount, e.g., 0.1-3wt % of an organic acid such as fulvic acid or humic acid, 0.5-4 wt %, achelating agent such as EDTA, 0.01-0.1% volume of a surfactant such assodium lauryl sulphate. This modified treatment composition may becombined with an amount of aqueous ammonium hydroxide solution 25-35 wt% at a ratio of 1:1 to 20:1, again noting that the treated natural gascannot contain more than 14 ppm ammonia. The combined amount (volume) ofthe treatment composition and ammonium hydroxide used in the remediationprocess will be approximately the same as the amount of modifiedtreatment composition discussed above for treating a mixed fluid ofcrude oil and natural gas, e.g., for a well having an output of5,000-10,000 barrels of crude oil and 10 million to 20 million ft³ ofnatural gas/day (24 hours) and wherein the H₂S content of the mixedfluid at 40,000 ppm or higher, the inventors have found that anappropriate amount of treatment composition is in a range of 5 to 20gallons of treatment composition added per hour or 120-480 gallons perday. Alternatively, ammonium hydroxide may be used as one of thehydroxide compounds in the modified treatment composition together withat least one other hydroxide compound, again, wherein the ratio of theat least one other hydroxide compound (collectively) to ammoniumhydroxide may be 1:1 to 20:1, again, with an amount of the modifiedtreatment composition in a range as discussed above. Because aqueoussolutions of ammonium hydroxide generally have concentrations of 25-35wt %, the overall concentration of the hydroxides in such treatmentcomposition may still be in a range of 35-55 wt %, but not asconcentrated as other treatment compositions according to the presentinvention which do not include ammonium hydroxide. Also, ammoniumhydroxide has a much greater vapor pressure than other hydroxidecompounds typically used in the treatment composition, e.g., sodiumhydroxide and potassium hydroxide, which may give the treatmentcomposition more effect on natural gas in the mixed fluid compared to atreatment composition according to the present invention which does notinclude ammonium hydroxide.

The present inventors have discovered that use of the modified treatmentcomposition including or combined with ammonium hydroxide is providedtwo significant effects. First, the overall content of sulfur basedcompounds remaining in the natural gas portion of the treated mixedfluid is reduced compared to use a treatment composition according tothe present invention which does not include ammonium hydroxide. Also,the ammonium hydroxide may cause some sulfur based compounds toprecipitate out of the treated mixed fluid, particularly if a relativelylarge amount of ammonium hydroxide is used, which may not be desirable.Second, the use of the modified treatment composition including orcombined with ammonium hydroxide will generally cause any salt containedin the water vapor contained in the natural gas portion of the mixedfluid to precipitate out. This would be very undesirable for if theprecipitated salt remains in the pipeline and clogs the pipeline, butmay be desirable in some situations, e.g., for use as a pre-treatment ofthe mixed fluid to remove salt before the mixed fluid enters thepipeline.

The foregoing description is given for clearness of understanding only,and no unnecessary limitations should be understood therefrom, asmodifications within the scope of the invention may be apparent to thosehaving ordinary skill in the art and are encompassed by the claimsappended hereto.

1. A treatment composition for remediating H₂S and other contaminant(s)in contaminated gases comprising: an aqueous hydroxide solutioncontaining at least one hydroxide compound at a collective concentrationof 35-55 weight percent of the aqueous hydroxide solution; at least oneorganic acid selected from the group consisting of fulvic acid and humicacid; and a chelating agent, wherein the aqueous hydroxide solutionconstitutes at least 80 wt % of the treatment composition, the at leastone organic acid constitutes 0.1-5 wt % of the treatment composition,the chelating agent constitutes 0.1-5 wt % of the treatment composition,and a pH of the treatment composition is at least 12.0, wherein thetreatment composition does not include metals apart from any metalscontained in the at least one hydroxide compound.
 2. The treatmentcomposition according to claim 1, wherein the chelating agent includesethylenediaminetetraacetic acid (EDTA), and the hydroxide compound(s)includes potassium hydroxide.
 3. The treatment composition according toclaim 1, further comprising at least one of a surfactant and a bufferingagent.
 4. The treatment composition according to claim 1, wherein atleast one hydroxide compound at a collective concentration of 45-55weight percent of the aqueous hydroxide solution and the aqueoushydroxide solution constitutes at least 90 wt % of the treatmentcomposition.
 5. A treatment process for remediating H₂S and othercontaminants in a contaminated gas also containing more than 1 ppm waterand ionic contaminants, comprising steps of: initially treating the gasin a water wash to remove some of the ionic contaminants in gas;increasing pressure of the gas after it is discharged from the waterwash using a compressor adding an amount of the treatment compositionaccording to claim 1 to the gas before and/or after the gas pressure isincreased using the compressor, and discharging the gas having theadditional amount of the treatment composition into an expanded volume.6-19. (canceled)
 20. The treatment process according to claim 5, whereinthe amount of treatment composition is added to the gas after thepressure of the gas is increased using the compressor and before the gasis discharged into the expanded volume.
 21. The treatment processaccording to claim 5, wherein the amount of treatment composition addedto the gas before and/or after the gas pressure is increased using thecompressor at a rate of about 1 gallon/30,000 ft³.
 22. The treatmentprocess according to claim 5, wherein the contaminated gas is naturalgas.
 23. A treatment process for selectively remediating H₂S and othercontaminants in a contaminated gas also containing more than 1 ppm waterand ionic contaminants, comprising steps of: combining a quantity of thetreatment composition according to claim 1 with a quantity of ahydrocarbon based liquid in a reaction vessel; flowing the contaminatedgas into a lower portion of the reaction vessel such that thecontaminated gas passes upward through the combined quantities of thetreatment composition and the hydrocarbon based liquid in the reactionvessel; and after the contaminated gas has passed through the combinedquantities of the treatment composition and the hydrocarbon based liquidin the reaction vessel, discharging the contaminated gas from an upperportion of the reaction vessel, wherein pH of the combined quantities ofthe treatment composition and the hydrocarbon based liquid in thereaction vessel is above
 7. 24. The treatment process according to claim23, wherein a ratio of combined amounts of the treatment composition andthe hydrocarbon based liquid is 40:60 to 60:40.
 25. The treatmentprocess according to claim 23, wherein the hydrocarbon based liquid hasan API rating in a range of about 30-50.
 26. The treatment processaccording to claim 23, wherein the contaminated gas has a contact timeof at least one second with the combined amounts of the treatmentcomposition and the hydrocarbon based liquid in the reaction vessel. 27.The treatment process according to claim 23, wherein the contaminatedgas is natural gas.
 28. A treatment process for selectively remediatingH₂S and other contaminants in a fluid mixture of contaminated liquid andcontaminated gas both containing more than 5 ppm H₂S, comprising stepsof: adding an amount of the treatment composition of claim 1 to thefluid mixture; and flowing the fluid mixture having the treatmentcomposition added thereto along a pipeline for a sufficient time topermit the treatment composition to reduce H₂S content in thecontaminated liquid below 5 ppm.
 29. The treatment process according toclaim 28, wherein the step of adding the treatment composition to thefluid mixture involves flowing the fluid mixture and the treatmentcomposition into a lower portion of a reaction vessel such that thefluid mixture and the treatment composition combine together andsubstantially fill the reaction vessel and the contaminated gas in thefluid mixture bubbles up through the contaminated liquid and thetreatment composition, and withdrawing a portion of the combined fluidmixture and the treatment composition from an upper portion of thereaction vessel and flowing the withdrawn portion into the pipeline. 30.The treatment process according to claim 29, wherein the step of addingthe treatment composition to the fluid mixture further involveswithdrawing a portion of the combined fluid mixture and the treatmentcomposition from the reaction vessel, adding more of the treatmentcomposition thereto and then flowing the withdrawn portion with thetreatment composition added thereto back into the lower portion of thereaction vessel.
 31. The treatment process according to claim 29,wherein the fluid mixture and the treatment composition flow into thelower portion of a reaction vessel through an elongate nozzle havingnumerous discharge defined therein.
 32. The treatment process accordingto claim 28, wherein the gas is natural gas from a well.
 33. Thetreatment process according to claim 28, wherein the amount of treatmentcomposition added to the fluid mixture added is in a range of 5 to 20gallons of treatment composition/a fluid mixture containing 8367 to17472 gallons of the contaminated liquid and 416,667 to 833,333 ft³ ofthe contaminated gas.